National Emission Standards for Hazardous Air Pollutants: Oil and Natural Gas Production and National Emission Standards for Hazardous Air Pollutants: Natural Gas Transmission and Storage
Federal RegisterJun 17, 1999
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SUMMARY: These promulgated national emission standards for hazardous
air pollutants (NESHAP) limit emissions of hazardous air pollutants
(HAP) from oil and natural gas production and natural gas transmission
and storage facilities. These final rules 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 69,000 megagrams per year (Mg/
yr) of HAP are emitted from facilities in these source categories. The
primary HAP emitted by the facilities covered by these final standards
include benzene, toluene, ethyl benzene, mixed xylenes (collectively
referred to as BTEX), and n-hexane. Benzene is carcinogenic and has
also been shown to cause various adverse health effects other than
cancer (i.e., noncancer effects). The other four HAP are not classified
as carcinogens based on available information; however, exposures to
these four HAP have been shown to cause various noncancer effects.
The EPA estimates that these promulgated NESHAP will reduce HAP
emissions from major sources in the oil and natural gas production
source category by 77 percent and from major sources in the natural gas
transmission and storage source category by 95.0 percent.
EFFECTIVE DATE: This regulation is effective June 17, 1999. See
SUPPLEMENTARY INFORMATION concerning judicial review.
ADDRESSES: Docket. A docket, No. A-94-04, containing information
considered by the EPA in developing the promulgated 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 5:30 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. The promulgated
regulations, background information document (BID) volumes 1 and 2, and
other supporting information are available for inspection and copying.
A reasonable fee may be charged for copying.
Responses to Comments Document. The responses to comments document
for the promulgated standards may be obtained from the EPA Library (MD-
35), Research Triangle Park, North Carolina 27711, telephone (919) 541-
2777, or from the National Technical Information Services, 5285 Port
Royal Road, Springfield, Virginia 22151, telephone (703) 605-6000 or
(800) 553-6847 or via the Internet at www.fedworld.gov/ntis/
ntishome.html. 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 Final Standards: Summary of Public Comments and
Responses'' (EPA-453/R-99-004b, May 1999). The document contains the
following: (1) a summary of all the public comments made on the
proposed standards and the Administrator's responses to the comments
and (2) a summary of the changes made to the standards since proposal.
This document is also available for downloading from the Technology
Transfer Network (see SUPPLEMENTARY INFORMATION).
FOR FURTHER INFORMATION CONTACT: For information concerning today's
action, contact Mr. Greg Nizich, Waste and Chemical Processes Group
(MD-13), U.S. Environmental Protection Agency, Research Triangle Park,
North Carolina 27711; telephone: (919) 541-3078; facsimile: (919) 541-
0246; or electronically at: [email protected].
SUPPLEMENTARY INFORMATION: Regulated Entities. Regulated categories and
entities include:
------------------------------------------------------------------------
Category Examples of regulated entities
------------------------------------------------------------------------
Industry............................... Condensate tank batteries,
glycol dehydration units,
natural gas processing plants,
and natural gas transmission
and storage facilities.
------------------------------------------------------------------------
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by these
actions. This table lists the types of entities that the EPA is now
aware could potentially be regulated by these actions. Other types of
entities not listed in the table could also be regulated. To determine
whether your facility is regulated by these actions, you should
carefully examine the applicability criteria in sections 63.760 and
63.1270 of the rules. If you have questions regarding the applicability
of these actions to a particular entity, consult the person listed in
the preceding FOR FURTHER INFORMATION CONTACT section.
Technology Transfer Network. This document, the final regulatory
texts, and BID volumes 1 and 2 are available in Docket No. A-94-04 from
the EPA's Air and Radiation Docket and Information Center (see
ADDRESSES). They can also be accessed through the EPA's Technology
Transfer Network (TTN) Internet web site at: http://www.epa.gov/ttn/
oarpg.
Judicial Review. National emission standards for hazardous air
pollutants for facilities in the oil and natural gas production and
natural gas transmission and storage source categories were proposed in
the Federal Register on February 6, 1998 (63 FR 6288). This Federal
Register action announces the EPA's final decisions on the rules. Under
section 307(b)(1) of the Act, judicial review of the NESHAP is
available only by filing a petition for review in the U.S. Court of
Appeals for the District of Columbia Circuit within 60 days of today's
publication of these final rules. Under section 307(b)(2) of the Act,
the requirements that are the subject of today's action may not be
challenged later in civil or criminal proceedings brought by the EPA to
enforce these requirements.
Preamble Outline. The following outline is provided to aid in
reading the preamble to the promulgated oil and natural gas production
and natural gas transmission and storage NESHAP.
I. Background
II. Summary of Considerations in Developing the Rules
A. Purpose of the Regulations
B. Technical Basis of the Regulations
C. Stakeholder and Public Participation
III. Summary of Promulgated Standards
A. Promulgated Standards for Oil and Natural Gas Production for
Major Sources
B. Promulgated Standards for Natural Gas Transmission and
Storage for Major Sources
C. Recordkeeping and Reporting Provisions
IV. Summary of Impacts
A. HAP Emission Reductions
B. Secondary Environmental Impacts
C. Energy Impacts
D. Cost Impacts
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E. Economic Impacts
V. Significant Comments and Changes to the Proposed Standards
A. Definition of Facility
B. Definition of ``Associated Equipment''
C. Applicability
D. Glycol Dehydration Unit Process Vent Standards
E. Storage Vessel Standards
F. Standards for Natural Gas Transmission and Storage
G. Monitoring, Recordkeeping, and Reporting Requirements
H. Cost and Economic Impacts
VI. Administrative Requirements
A. Docket
B. Paperwork Reduction Act
C. Executive Order 12866: A Significant Regulatory Action
Determination
D. Regulatory Flexibility Act
E. Congressional Review Act
F. Unfunded Mandates Reform Act
G. Executive Order 12875: Enhancing the Intergovernmental
Partnership
H. Executive Order 13045: Protection of Children from
Environmental Health Risks and Safety Risks
I. Executive Order 13084: Consultation and Coordination with
Indian Tribal Governments
J. National Technology Transfer and Advancement Act
The following conversions from metric to English units are provided
to aid in reading the preamble to the promulgated oil and natural gas
production and natural gas transmission and storage NESHAP.
----------------------------------------------------------------------------------------------------------------
Metric values Equivalent English values
----------------------------------------------------------------------------------------------------------------
0.31 cubic meter per liter (m3/ 1,750 standard cubic feet per barrel (ft 3/barrel).
liter).
39,700 liter/day................... 250 barrels per day (bpd).
79,500 liter/day................... 500 bpd.
0.90 Megagrams per year (Mg/yr).... 1.0 ton per year (tpy).
18.4 thousand cubic meters per day 650 thousand cubic feet per day (scf/day).
(m3/day).
28.3 thousand m3/day............... 1 million scf/day (MMscf/day).
85 thousand m3/day................. 3 MMscf/day.
283 thousand m3/day................ 10 MMscf/day.
----------------------------------------------------------------------------------------------------------------
I. Background
Section 112(b) of the Act lists 188 HAP and directs the EPA to
develop rules to control all major and some area sources emitting HAP.
On July 16, 1992 (57 FR 31576), the EPA published a list of major and
area sources for which NESHAP are to be published (i.e., the source
category list). Oil and natural gas production facilities were listed
as a category of major sources.
The EPA included natural gas transmission and storage facilities in
the proposed initial listing of source categories that was published in
1991. Comments received on the proposed initial list indicated that
this source category did not contain major sources of HAP. As a result,
natural gas transmission and storage facilities were not included as a
distinct source category in the July 1992 final list of source
categories of major sources of HAP.
During the development of the standards for the oil and natural gas
production source category, information was obtained on glycol
dehydration unit HAP emissions that are representative of both oil and
natural gas production facilities and natural gas transmission and
storage facilities. The information indicated that natural gas
transmission and storage facilities have the potential to be major HAP
sources. In addition, representatives of the natural gas transmission
and storage source category stated to the EPA that there are major
source glycol dehydration units in the source category. Therefore, the
EPA amended the source category list on February 12, 1998 (63 FR 7155)
to add natural gas transmission and storage as a major source category.
On February 6, 1998, the EPA also gave notice of its intention to
add oil and natural gas production as an area source category (63 FR
6291), but did not amend the source category list to include such a
category. In order to ensure that regulations applicable to the area
source category are consistent with the Urban Air Toxics Strategy, to
be implemented under section 112(k) of the Act, the EPA has deferred
the regulation of oil and natural gas production facilities which are
area sources until the Urban Air Toxics Strategy is finalized. The EPA
expects this strategy to be finalized later this year.
II. Summary of Considerations in Developing the Rules
A. Purpose of the Regulations
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 67,000 Mg/yr of HAP are emitted from
facilities in the oil and natural gas production source category and
2,100 Mg/yr of HAP are emitted from facilities 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 likelihood of these adverse health effects
depends on the range of ambient concentrations and the amount,
frequency, and duration of exposures. The ambient concentrations are
influenced by source-specific characteristics such as emission rates
and local meteorological conditions. Exposure and health impacts due to
the ambient concentrations are dependent on multiple factors that
affect human variability such as genetics, age, health status (e.g.,
the presence of pre-existing disease), lifestyle, location of
residence, activity patterns, and other factors.
Benzene, one of the HAP associated with these NESHAP, is classified
as a known human carcinogen based on convincing human evidence (such as
observed increases in the incidence of leukemia in exposed workers), as
well as supporting evidence from animal studies. 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
[[Page 32612]]
irregular heartbeat. Repeated exposure to high concentrations may cause
additional nervous system effects, including incoordination, tremors,
death of brain cells, involuntary eye movements, and may impair speech,
hearing, and vision. Long-term exposure to toluene by 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 have been exposed to high levels of 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 by 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 to determine its carcinogenic potential.
Short-term inhalation of high levels of mixed xylenes (a mixture of
three closely-related compounds) by 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 include labored breathing, heart palpitation, severe
chest pain, abnormal heart functioning, and possible effects on the
blood and kidneys. Developmental effects have been reported in animals
from xylene exposure via inhalation. Not enough information exists to
determine the carcinogenic potential of mixed xylenes.
Short-term inhalation of high levels of n-hexane by 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 to high levels of n-hexane by humans has
been reported to 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 to determine its carcinogenic potential.
The EPA estimates that the NESHAP will reduce HAP emissions from
those impacted HAP emission points in the oil and natural gas
production source category by 77 percent and will reduce HAP emissions
from impacted glycol dehydration units in the natural gas transmission
and storage source category by 95.0 percent.
B. Technical Basis of Regulations
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 that reflect the maximum degree of reduction in HAP emissions
through application of maximum achievable control technology (MACT).
Further, the EPA is required to 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 final 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.
Prior to proposal, 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. These companies provided
information on their representative facilities.
This information was used, in part, as the technical basis for
determining the MACT level of control for the emission points covered
under the final standards. In addition to information collected in the
questionnaires, the EPA considered information available in the general
literature, information submitted by industry on technical issues
subsequent to the questionnaire responses, and additional information
received during the public comment period for the proposed rules, in
developing the final rules.
C. Stakeholder and Public Participation
In the development of these final standards, numerous
representatives of the oil and natural gas production industry, the
natural gas transmission and storage industry, and other interested
parties were consulted. Industry representatives 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 for evaluating HAP
emissions and air emission controls for the final standards.
The standards for the oil and natural gas production and natural
gas transmission and storage source categories were proposed in the
Federal Register on February 6, 1998 (63 FR 6288). The preamble to the
proposed standards described the rationale for the proposed standards.
Public comments were solicited at the time of proposal. To provide
interested parties the opportunity for oral presentation of data,
views, or arguments concerning the proposed standards, a public hearing
was offered at proposal. However, the public did not request a hearing
and, therefore, one was not held. The public comment period was from
February 6, 1998 to April 7, 1998. Fifty comment letters were received.
Commenters included industry representatives, trade associations, State
agencies, and other interested parties.
On January 15, 1999, in response to comments received on the
proposal, the EPA also published a supplemental notice announcing the
availability of additional data collected from facilities in the
natural gas transmission and storage source category (64 FR 2611). Four
comment letters were received from industry representatives and trade
associations.
All of the comments were carefully considered and changes were made
to the proposed standards when determined by the EPA to be appropriate.
A detailed discussion of these comments and responses can be found in a
document entitled ``National Emissions Standards for Hazardous Air
Pollutants for Source Categories: Oil and Natural Gas Production and
Natural Gas Transmission and Storage--Background Information for Final
Standards: Summary of Public Comments and Responses'' (BID volume 2),
which is
[[Page 32613]]
referenced in the ADDRESSES section of this preamble (EPA-453/R/99-
004b, May 1999). The summary of comments and responses in the BID
volume 2 serves as the basis for the revisions that have been made to
the standards between proposal and promulgation. Section V of this
preamble discusses the major changes.
III. Summary of Promulgated Standards
A. Promulgated Standards for Oil and Natural Gas Production for Major
Sources
This final action amends title 40, chapter I, part 63 of the Code
of Federal Regulations by adding a new Subpart HH--National Emission
Standards for Hazardous Air Pollutants from Oil and Natural Gas
Production Facilities. The standards apply to owners and operators of
facilities that process, upgrade, or store (1) hydrocarbon liquids
(with the exception of those facilities that exclusively handle black
oil) to the point of custody transfer and (2) natural gas from the well
up to and including the natural gas processing plant. The standards
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.
As required by the Act, the determination of a facility's potential
to emit HAP and, therefore, its status as a major source, is based on
the total of all HAP emissions from all activities at a facility,
except that section 112(n)(4) of the Act prohibits aggregating
emissions from oil or gas exploration or production wells (and their
associated equipment) and emissions from pipeline compressor or pump
stations with emissions from other similar units. A definition of
associated equipment is contained in the final standards.
To determine potential emissions for determining major source
status, the final standards specify that an owner or operator that can
document a decline in annual production each year for 5 years prior to
the effective date of the rule must calculate the maximum facility
throughput as the average of the annual throughput for the 3 years
prior to the effective date of the rule, multiplied by 1.2. If any
increase in production is observed over the 5 years prior to the
effective date of the rule, the owner or operator must calculate the
maximum facility throughput as the maximum annual throughput over the 5
years prior to the effective date times 1.2. The owner or operator must
recalculate the maximum throughput if actual annual throughput
increases to a rate above the calculated values. In addition, for other
parameters used to estimate emissions, the owner or operator must use
the maximum value measured over the period for which the maximum
throughput is calculated and may be determined as an annual average or
the highest single measured value.
1. Applicability
The final standards for oil and natural gas production facilities
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, or a combination of both. In addition, the owner or operator
of a natural gas processing plant that is a major source of HAP is
required to reduce HAP emissions from equipment leaks by establishing a
leak detection and repair (LDAR) program.
The following are exempt from the requirements of subpart HH:
Owners and operators of facilities that exclusively
process, handle, and store black oil are not subject to the final
standards. Black oil is defined in the final rule as a hydrocarbon
liquid with an initial gas-to-oil ratio (GOR) less than 0.31 cubic
meters per liter (m3/liter) and an American Petroleum
Institute (API) gravity less than 40 degrees. For this subpart, a
facility that uses natural gas for fuel or generates gas from black oil
still qualifies for this exemption.
Oil and natural gas production facilities prior to the
point of custody transfer that have a facilitywide actual annual
average natural gas throughput less than 18.4 thousand cubic meters per
day (m3/day), and a facilitywide actual annual average
hydrocarbon liquid throughput less than 39,700 liters per day (liter/
day.) Oil and natural gas production facilities after the point of
custody transfer, including natural gas processing plants, do not
qualify for these exemptions.
2. Glycol Dehydration Unit Process Vent Standards
The MACT standard for process vents on new and existing glycol
dehydration units was set at the floor level of control. To determine
the MACT floor, the EPA divided glycol dehydration units into two
sizes: (1) small glycol dehydration units with actual annual average
natural gas throughputs less than 85 thousand m3/day or with
actual average benzene emissions less than 0.90 Mg/yr, and (2) large
glycol dehydration units with actual annual average natural gas
throughputs equal to or greater than 85 thousand m3/day or
with actual average benzene emissions equal to or greater than 0.90 Mg/
yr. For small glycol dehydration units, the EPA determined that the
MACT floor was no control and that it was not cost effective to select
a regulatory alternative beyond the floor.
For large glycol dehydration units, the EPA reviewed the
information that was available to develop a MACT floor (a detailed
discussion of the development of the MACT floor can be found in the
docket, Air Docket A-94-04). This information consisted of data
gathered from: (1) industry responses to the EPA's Air Emission Survey
Questionnaires, (2) site visits, (3) meetings with stakeholders, and
(4) literature.
As required under section 112(d) of the Act, the EPA developed the
MACT floor based on ``* * * the average limitation achieved by the best
performing 12 percent of the existing sources * * *.'' The EPA obtained
information on 200 glycol dehydration units that were considered to be
major sources of HAP (prior to control). Of these, 34 percent (67
units) were controlled using a variety of control technologies,
including: condensation, combustion, and a combination of condensation
and combustion. The types of control technologies used by the industry
have been demonstrated, in other applications, to achieve varying
levels of emission reduction (ranging from 95.0 to 98 percent or
better). The EPA could not identify a technical basis for the variation
in the performance levels achieved by the controls reported to be used
to control process vents on glycol dehydration units. In order to
account for the variability in HAP emission reduction efficiencies, the
EPA selected 95.0 percent as the required emission reduction (i.e., the
MACT floor) for large glycol dehydration units in the oil and natural
gas production source category.
The final standards require that all process vents on new and
existing 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, on
an annual average basis; or (2) the actual average benzene emissions
from the glycol dehydration unit are less than 0.90 Mg/yr. Glycol
dehydration units that meet these criteria are not subject to the
control requirements of subpart HH.
Glycol dehydration units that are subject to the control
requirements are required to connect, through a closed-vent system,
each process vent on the glycol dehydration unit to an air
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emission control system. The control system must reduce emissions: (1)
by 95.0 percent or more of HAP, (2) to an outlet concentration of 20
parts per million by volume (ppmv) or less (for combustion devices), or
(3) to a benzene emission level of 0.90 Mg/yr or less. Pollution
prevention measures, such as process modifications or combinations of
process modifications and one or more control devices that reduce the
amount of HAP emissions generated, are allowed as an alternative
provided they achieve the required emission reductions.
3. Storage Vessel Standards
Final standards are established for existing and new storage
vessels with the potential for flash emissions that are located at
major HAP sources. Storage vessels with the potential for flash
emissions are defined as those that contain a hydrocarbon liquid with a
storage tank GOR equal to or greater than 0.31 m3/liter, an
API gravity equal to or greater than 40 degrees, and an actual annual
average throughput of hydrocarbon liquids equal to or greater than
79,500 liter/day.
Flash emissions from storage vessels 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 final standards require
that storage vessels with the potential for flash emissions be equipped
with an air emission control system.
Under the final standards, a storage vessel with the potential for
flash emissions is required to be equipped with a cover vented through
a closed-vent system to a control device that (1) recovers or destroys
HAP emissions with an efficiency of 95.0 percent or greater, or (2) for
combustion devices, reduces HAP emissions to an outlet concentration of
20 ppmv or less.
A pressurized storage vessel that is designed to operate as a
closed system is considered in compliance with the promulgated
requirements for storage vessels. In addition, owners or operators that
are meeting the requirements of 40 CFR part 60, subpart Kb; 40 CFR part
63, subpart G; or 40 CFR part 63, subpart CC, are also considered in
compliance.
4. Standards for Equipment Leaks
The final rule requires owners and operators of natural gas
processing plants that are major HAP sources to control HAP emissions
from leaks from ancillary equipment and compressors that contain or
contact a liquid or gas that has a total volatile hazardous air
pollutant (VHAP) concentration equal to or greater than 10 percent by
weight. The final equipment leak standards do not apply to ancillary
equipment and compressors that operate in VHAP service less than 300
hours per year. Also, an owner or operator that is subject to and
controlled under the provisions of 40 CFR part 60, subpart KKK; or 40
CFR part 61, subpart V; or 40 CFR part 63, subpart H, is only required
to comply with the requirements of that subpart.
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 where necessary, perform equipment modifications. 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 (1) at a nonfractionating facility that processes less than
283 thousand m3/day, or (2) on the Alaskan North Slope, are
exempt from some of the routine LDAR monitoring requirements. In
addition, reciprocating compressors in wet gas service are exempt from
the compressor requirements.
5. Air Emission Control Equipment Requirements
Specific performance and operating requirements are included for
each control device installed by the owner or operator. Control devices
are required to reduce the mass content of the gases vented to the
device (1) by 95.0 percent or greater by weight as total organic
compounds (TOC), less methane and ethane, or total HAP; or (2) for
combustion devices, to an outlet HAP or TOC concentration of 20 ppmv or
less.
Closed vent systems that contain bypass devices that could divert
vent streams away from the control device must either install a flow
indicator or secure the bypass valve in the nondiverting position to
ensure that the control device is not bypassed.
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 installed on storage vessels.
6. Test Methods and Procedures
An owner or operator must be able to demonstrate that the criteria
for exemptions from control requirements are met when controls are not
applied or when existing controls are adequate to meet the exemption
criteria. For example, owners or operators of glycol dehydration units
that do not install air emission controls because the actual average
benzene emission rate from the unit is less than 0.90 Mg/yr must be
able to demonstrate that the actual average benzene emission rate from
the unit is less than 0.90 Mg/yr.
Procedures for demonstrating the HAP emission reduction efficiency
of control devices and HAP concentration are consistent with procedures
established in previously promulgated NESHAP that apply to emission
sources similar to those addressed in the final standards. Engineering
calculations, modeling (using EPA-approved models), and previous test
results are generally acceptable means of demonstrating compliance,
except where such means are not conclusive. Test procedures are
specified in the final rule for use when testing is required to
demonstrate compliance.
An alternative test procedure is provided to demonstrate control
efficiency 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 the detection of
leaks from ancillary equipment and compressors and leaks in covers and
closed vent systems.
7. Monitoring and Inspection Requirements
The final standards require that the owner or operator periodically
inspect and monitor air emission control equipment. Periodic
inspections are 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 is required to
periodically perform these inspections to determine and ensure that
these equipment operate with no leaks.
For covers, the owner or operator is required to perform initial
and semiannual visual inspections. For closed vent systems, the owner
or operator is required to perform an initial leak inspection and
annual visual inspections to detect leaks. In addition, the owner or
operator of closed vent system components that are not permanently or
semi-permanently sealed must perform annual leak inspections.
The final standards require continuous monitoring of control device
operation through the use of automated instrumentation. Continuous
monitoring systems measure and record control
[[Page 32615]]
device operating parameters to ensure compliance with the standards.
8. Recordkeeping and Reporting Requirements
The recordkeeping and reporting requirements associated with the
final standards are primarily those specified in the part 63 General
Provisions (40 CFR 63, subpart A). Major sources are subject to all of
the requirements of the General Provisions with the exception that (1)
owners or operators are allowed up to 1 year from the effective date of
the standards to submit the initial notification described in
Sec. 63.9(b) of subpart A; and (2) owners or operators are allowed to
submit Periodic reports and startup, shutdown, and malfunction reports
semiannually instead of quarterly. The EPA selected these specific
exceptions due to the large number of facilities that need to submit
notifications or reports related to the NESHAP. The EPA believes that
these exceptions will not adversely affect the implementation of the
final regulation or reduce its impact on HAP emissions.
B. Promulgated Standards for Natural Gas Transmission and Storage for
Major Sources
The final standards 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 apply to owners and operators of facilities that process,
upgrade, transport or store natural gas prior to delivery to a local
distribution company (LDC) or a final end user if no LDC is present. A
compressor station that transports natural gas to a natural gas
processing plant is considered a part of the oil and natural gas
production source category.
A facility's potential to emit is required to be calculated based
on a maximum facility throughput. For storage facilities or facilities
that store and transport natural gas, the final rule specifies
procedures for calculating this maximum throughput based on the
facility's maximum withdrawal and injection rates and the working gas
capacity of the storage field. Facilities that only transport natural
gas are required to calculate maximum throughput as the highest annual
throughput over 5 years prior to the effective date of the rule,
multiplied by 1.2. The owner or operator must also establish maximum
values of other parameters required to calculate emissions over the
same period used to determine maximum throughput.
1. Applicability
The final standards for natural gas transmission and storage
facilities require that the owner or operator of a major source of HAP
reduce HAP emissions from glycol dehydration units through the
application of air emission control equipment or pollution prevention
measures, or a combination of both. The owner or operator of a facility
that processes less than 28.3 thousand m3/day of natural gas
facilitywide on an actual annual average basis, where glycol
dehydration units are the only HAP emission points, is exempt from the
requirements of subpart HHH.
2. Glycol Dehydration Unit Process Vent Standards
The MACT standard for process vents on new and existing glycol
dehydration units was set at the floor level of control. To determine
the MACT floor, the EPA divided glycol dehydration units into two
sizes: (1) small glycol dehydration units with actual annual average
natural gas throughputs less than 283 thousand m3/day or
with actual average benzene emissions less than 0.90 Mg/yr, and (2)
large glycol dehydration units with actual annual average natural gas
throughputs equal to or greater than 283 thousand m3/day or
with actual average benzene emissions equal to or greater than 0.90 Mg/
yr. As discussed in the January 15, 1999 supplemental notice (64 FR
2611), the EPA determined that the MACT floor for large glycol
dehydration units was 95.0 percent control. For small glycol
dehydration units, the EPA determined that the MACT floor was no
control and that it was not cost effective to select a regulatory
alternative beyond the floor.
The final standards require that all process vents on new and
existing glycol dehydration units that are located at major HAP sources
be controlled unless (1) the actual annual average flowrate of natural
gas to the glycol dehydration unit is less than 283 thousand
m3/day, or (2) the actual average benzene emissions from the
glycol dehydration unit are less than 0.90 Mg/yr.
Glycol dehydration units that are subject to the control
requirements are required to connect, through a closed-vent system,
each process vent on the glycol dehydration unit to an air emission
control system that reduces emissions: (1) by 95.0 percent or more of
HAP, (2) to an outlet HAP concentration of 20 ppmv or less, for
combustion devices, or (3) to a benzene emission level of 0.90 Mg/yr or
less. As with the final standards for the oil and natural gas
production NESHAP, pollution prevention measures, such as process
modifications (or combinations of process modifications and control
devices) that reduce the amount of HAP emissions generated, are allowed
as an alternative provided they achieve the required emission
reductions.
3. Air Emission Control Equipment Requirements
Specific performance and operating requirements are included for
each control device installed by the owner or operator. Control devices
are required to reduce the mass content of the gases vented to the
device (1) by 95.0 percent or greater by weight as TOC, less methane
and ethane, or total HAP; or (2) for combustion devices, to an outlet
HAP or TOC concentration of 20 ppmv or less.
Closed vent systems that contain bypass devices that could divert
vent streams away from the control device must either install a flow
indicator or secure the bypass valve in the nondiverting position to
ensure that the control device is not bypassed.
4. Test Methods and Procedures
An owner or operator must be able to demonstrate that the criteria
for exemptions from control requirements are met when controls are not
applied or when existing controls are adequate to meet the exemption
criteria. For example, owners or operators of glycol dehydration units
that do not install air emission controls because the actual average
benzene emission rate from the unit is less than 0.90 Mg/yr must be
able to demonstrate that the actual average benzene emission rate from
the unit is less than 0.90 Mg/yr.
Procedures for demonstrating the HAP emission reduction efficiency
of control devices and HAP concentration are consistent with procedures
established in previously promulgated NESHAP that apply to emission
sources similar to those addressed in the final standards. Engineering
calculations, modeling (using EPA-approved models), and previous test
results are generally acceptable means of demonstrating compliance,
except where such means are not conclusive. Test procedures are
specified in the final rule for use when testing is required to
demonstrate compliance.
An alternative test procedure is provided to demonstrate control
efficiency 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
[[Page 32616]]
associated with testing the inlet to a condenser in this application.
Procedures and test methods are also specified for detection of leaks
in closed-vent systems.
5. Monitoring and Inspection Requirements
The monitoring and inspection requirements are (1) periodic control
equipment monitoring, (2) initial leak detection inspections for
closed-vent systems to ensure all fittings are leak-tight, (3) annual
visual inspections of closed-vent systems (closed vent system
components that are not permanently or semi-permanently sealed are also
required to be annually inspected for leaks), and (4) continuous
monitoring of control device operation. Continuous monitoring requires
the use of automated instrumentation that measures and records control
device compliance operating parameters.
C. Recordkeeping and Reporting Provisions
The recordkeeping and reporting requirements associated with the
final standards are primarily those specified in the part 63 General
Provisions (40 CFR 63, subpart A). Major sources are subject to all of
the requirements of the General Provisions, except that (1) owners or
operators are allowed up to 1 year from the effective date of the
standards to submit the initial notification required under
Sec. 63.9(b) of subpart A and (2) owners or operators are allowed to
submit Periodic reports and startup, shutdown, and malfunction reports
semiannually instead of quarterly. These exceptions were selected to
maintain consistency between the major source provisions of the final
regulations for natural gas transmission and storage facilities and oil
and natural gas production facilities.
IV. Summary of Impacts
A. HAP Emission Reductions
For major sources, the EPA estimated that the final oil and natural
gas production standards for existing sources will 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 standards.
Table 1 presents the major source emission reductions, in addition
to other environmental, energy, and cost impacts, that the EPA
estimates will occur from the implementation of the standards for oil
and natural gas production.
Table 1.--Summary of Estimated Environmental, Energy, and Economic Impacts Existing and New Major Sources
----------------------------------------------------------------------------------------------------------------
Existing
Existing oil New oil and natural gas
Impact category and natural natural gas transmission
gas production production and storage *
----------------------------------------------------------------------------------------------------------------
Estimated number of impacted facilities......................... 440 44 7
Emission reductions (Mg/yr):
HAP......................................................... 30,000 3,000 390
VOC......................................................... 61,000 6,100 610
Methane..................................................... 7,000 700 230
Secondary environmental emission increases (Mg/yr):
Sulfur oxides............................................... X) and carbon monoxide (CO) and less than 5 Mg/yr for
nitrogen oxides (NOX). These estimates are for major oil and
natural gas production sources.
The anticipated increases in secondary air pollutant emissions are
based on six affected facilities utilizing flares and are estimated to
be less than 1.0 Mg/yr for SOX, CO, and NOX,
each, from the implementation of the 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 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 standards.
C. Energy Impacts
Energy impacts are those energy requirements associated with the
operation of emission control devices. The EPA estimated that the
operation of add-on control devices (e.g., condensers, flares, etc.)
would not require additional energy. Vapor collection and redirect
systems used for the control of emissions from a fixed-roof storage
vessel require electricity for operation of the primary components of
the system, including fans and blowers.
The EPA estimated that the annual energy requirements for each
vapor collection/recovery system installed to comply with the oil and
natural gas production storage vessel standards are estimated to be 300
kilowatt hours per year (kW-hr/yr). The EPA also estimated that
approximately 125 oil and natural gas production major source
facilities would install this control option. The national energy
demand increase for existing sources was estimated to be 38,000 kW-hr/
yr.
Because storage vessels are not regulated under the natural gas
transmission and storage NESHAP, the EPA estimated that there would be
no national energy demand increase from the operation of any of the
control options analyzed under the natural gas transmission and storage
standards for major sources.
The 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 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 rule for
existing major sources in the oil and natural gas production source
category is approximately $6.5 million. The total capital cost for new
major sources is estimated to be approximately $700,000.
The total estimated net annual cost to industry to comply with the
requirements for existing major sources in the oil and natural gas
production source category is approximately $4.0 million per year. The
total net annual cost for new major sources is approximately $400,000
per year. These estimated annual costs include (1) the cost of capital;
(2) operating and maintenance costs; (3) the cost of monitoring,
recordkeeping, and reporting (MRR); and (4) any associated product
recovery credits.
The estimated total capital cost to comply with the rule for major
sources in the natural gas transmission and storage source category is
approximately $280,000.
The total estimated net annual cost to industry to comply with the
requirements for major sources in the natural gas transmission and
storage source category is approximately $300,000. 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 MRR, and (4) any associated
product recovery credits.
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 profitability. Price and output changes as
a result of the regulation are less than 0.0005 of 1 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 $4.6 million,
which 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. Significant Comments and Changes to the Proposed Standards
In response to comments received on the proposed standards, several
changes have been made to the final rules. While several of these
changes are clarifications designed to clarify the Agency's original
intent, a number of them are significant changes to the proposed
standard requirements. A summary of the substantive comments and/or
changes made since proposal are described in the following sections.
Detailed Agency responses to public comments and the revised analysis
for the final rule are contained in the BID, volume 2 (EPA-453/R-99-
004b, May 1999) and docket (see ADDRESSES section of this preamble).
A. Definition of Facility
The EPA developed the proposed definition of facility to (1)
identify criteria that define a grouping of emission points that meet
the intent of the language contained in section 112(a)(1) of the Act:
``* * * located within a contiguous area and under
[[Page 32618]]
common control, * * *''; and (2) contain terms that are meaningful and
easily understood within the regulated industries. The proposed
definition was based on individual surface sites and the idea 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 tract) shall not be aggregated. In addition, the proposed
definition of a production field facility was limited to glycol
dehydration units and storage vessels with the potential for flash
emissions. The EPA requested comments on the proposed definition of
facility. Specifically, the EPA requested 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 whether another definition would better implement this intent.
Several commenters responded to the EPA's request for comments on
the definition of facility. The commenters requested clarification of,
or suggested changes to, the proposed definition of facility. The
commenters were primarily concerned that large groupings of equipment
would inappropriately be considered a part of the same facility,
resulting in a major source determination. In particular, the
commenters were concerned about how subparts HH and HHH would treat
units, contiguous surface sites, and surface sites with equipment under
separate ownership. The commenters requested clarification of the
definition of facility to prevent this confusion.
The EPA intended that the 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.
The EPA believes that it would not be reasonable to aggregate
emissions from surface sites that are located on the same lease, but
are great distances apart. The definition of facility states that
equipment located on different oil and natural gas properties (e.g.,
leases) are not to be aggregated. Although units (which are made up of
more than lease or tract) are under common control, under the
definition of facility, the equipment located on different leases
contained within each unit would not be aggregated.
Under section 112(a)(1) of the Act, a major source is defined as
``* * * any stationary source or group of stationary sources located
within a contiguous area and under common control.* * *'' The EPA
believes that by defining facility based on individual surface sites,
the EPA has provided relief for individual surface sites that are
located on the same lease, but are far apart, and excluding contiguous
surface sites located on the same lease would be contrary to the intent
of the Act.
Finally, the terms contained in the definition of facility (e.g.,
surface site and lease) are well understood within the industry and by
enforcement agencies, and the EPA does not believe that additional
definitions or clarifications regarding these terms are necessary.
In response to comments regarding specific clarification to the
definition of facility, the EPA has made several changes to the
definition of facility. The EPA modified the definition of facility to
point to the definition of ``surface site.'' In subpart HHH, the EPA
has added a definition of ``surface site,'' and modified the definition
of facility to point to the new definition of ``surface site.''
The EPA further modified the definition of facility in subpart HH
by: (1) specifying that ``upgraded'' means ``the removal of impurities
or other constituents to meet contract specifications''; (2) changing
the term ``unit areas'' to ``surface unit areas''; and (3) specifying
that separate surface sites, whether or not connected by a road,
waterway, power line or pipeline, would not be considered a part of the
same facility.
Commenters recommended that the EPA expand its definition of
production field facility in subpart HH to include additional HAP
emission points beyond glycol dehydration units and storage vessels
with flash emission potential. The concern was that several facilities
that could otherwise be major sources of HAP would be exempt from
subpart HH under the proposed definition of facility.
One of the EPA's objectives was to develop a definition of facility
that would comply with section 112(n)(4) of the Act and at the same
time, reduce the burden on owners and operators in making a major
source determination. The EPA's evaluation of HAP emission sources in
production field operations suggested that other potential HAP emission
points at these facilities (e.g., equipment leaks) would be
inconsequential to the determination of a facility's major source
status. The EPA believes that eliminating the need to quantify HAP
emissions from small sources at production field facilities would not
affect the major source status determination, but would reduce the
burden on owners or operators.
Other commenters requested that the EPA clarify, within the
definition of facility in subpart HHH, whether the EPA intended to
exclude facilities used to store natural gas after the gas enters the
local distribution system of a gas utility. The commenter recommended
that the EPA clarify that the definition of facility applies all the
way to the end user only if there is no local distribution company.
The affected source in the natural gas transmission and storage
source category should run all the way to the end user only if there is
no local distribution company. Therefore, the EPA modified the
definition of facility in subpart HHH to state that if there is not a
local distribution company, the facility runs to the end user.
Some commenters were concerned that the definition of facility in
subpart HH suggests that a natural gas storage facility could qualify
as a production facility, since natural gas storage takes place in
depleted gas wells, and liquids are transferred for processing to the
plant.
Subpart HH contains a definition of field natural gas which means
``* * * natural gas that is extracted from a production well prior to
entering the first stage of processing, such as dehydration.'' In
addition, a production well is defined in Sec. 63.761 as a ``* * * hole
drilled in the earth from which * * * field natural gas is extracted.''
Since the gas handled by a natural gas storage facility has been
dehydrated, the EPA believes that the natural gas handled by a storage
facility would not be considered field natural gas. Therefore, given
the definitions of production well and field natural gas, a natural gas
storage field that uses a depleted gas well for storage would not
qualify as a production facility. The EPA does not believe that
clarification of the definition of facility is necessary in response to
this comment.
B. Definition of ``Associated Equipment''
Section 112(n)(4)(A) of the Act states:
* * * 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 or
gas exploration or production well (with its associated equipment),
such emissions shall not be aggregated for any purpose under this
section.
[[Page 32619]]
According to the statutory definition of major source in section
112(a)(1) of the Act, HAP emissions from all emission points within a
contiguous area and under common control must be counted in a major
source determination. By stating that emissions from any oil and gas
production and exploration well (with its associated equipment) cannot
be aggregated for a major source determination, the provisions of
section 112(n)(4)(A) mean HAP emissions from each well and each piece
of equipment considered to be associated with the well must be
evaluated separately in a major source determination. That is, any well
or piece of associated equipment would only be determined to be a major
source if HAP emissions from that well or piece of associated equipment
were major.
Therefore, to implement this special provision of the Act for the
oil and natural gas production source category, a definition of
``associated equipment'' was necessary. However, a definition for the
term ``associated equipment'' was not provided in the statute. The EPA
proposed 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 the
potential for flash emissions would not be associated equipment. In
developing this proposed definition, the Agency identified and
evaluated several options. The Agency also sought and received input
from industry and other stakeholders.
In the proposal, the EPA specifically requested comments on the
proposed definition of ``associated equipment.'' The EPA requested that
commenters disagreeing with the proposal provide alternative definition
options, along with supporting documentation, that would provide the
relief that Congress intended for this industry in section 112(n)(4),
while preserving the EPA's ability to regulate HAP emissions from
glycol dehydration units and storage vessels with the potential for
flash emissions.
Several commenters responded to the EPA's request for comments on
the EPA's interpretation of the term ``associated equipment'' as used
in section 112(n)(4) of the Act. Although several commenters did not
fully support the EPA's interpretation of section 112(n)(4), they
acknowledged that the proposed definition of associated equipment is a
workable solution in comparison to other options for this definition.
According to the commenters, aggregation of glycol dehydration units
and storage vessels with flash emission potential would result in the
same major source determination as aggregation of all potential
sources, but would reduce the burden on the facility operator. Other
commenters argued that section 112(n)(4) mandates no aggregation of
emissions from individual sources at oil and gas production fields, and
that the EPA exceeded its statutory authority by allowing for the
aggregation of emissions from glycol dehydration units and storage
vessels with the potential for flash emissions.
After consideration of these comments, the EPA agrees with those
commenters who supported the proposed definition as a workable
solution, and is promulgating the definition as proposed. The EPA
disagrees with those commenters who argued that the Agency exceeded its
statutory authority for the reasons discussed below.
Section 112(a)(1) generally requires HAP emission points within a
contiguous area and under common control to be aggregated in a major
source determination for the purposes of section 112. While this
approach is appropriate for facilities in most industries, it may lead
to unreasonable aggregations if strictly applied to oil and natural gas
field operations. Given that some oil and natural gas operations (e.g.,
a production field) may cover several square miles or that leases and
mineral rights agreements give some companies control over a large area
of contiguous property, determination of major source status strictly
by the language of section 112(a)(1) could mean in this industry that
HAP emissions must be aggregated from emission points separated by
large distances.
Congress addressed the unique aspects of the oil and natural gas
production industry by providing the special provisions in section
112(n)(4) of the Act referring to the ``* * * oil and gas exploration
and production well (and its associated equipment) * * *.'' However,
Congress did not provide a definition of the term ``associated
equipment'' in the statutory language, leaving its interpretation to
the EPA. A definition of this term is important in determining the
major source status of facilities in both the oil and natural gas
production and the natural gas transmission and storage source
categories.
In the absence of clear guidance in the statute, the EPA evaluated
various options for defining ``associated equipment'' prior to
proposal. The EPA's objective was to arrive at a reasonable
interpretation that would (1) provide substantive meaning to the term
``associated equipment'' consistent with congressional intent; (2)
prevent the aggregation of small, scattered HAP emission points in
major source determinations; (3) be easily implementable; and (4) not
preclude the aggregation of significant HAP emission points in the
source category. Due to the lack of clarity in the statute and the
potential impact on major source determinations, the Agency worked with
industry stakeholders to identify and evaluate options prior to
proposal. Industry representatives expressed their goals for the
interpretation of associated equipment, and provided information on the
magnitude of HAP emission points and the potential impacts of various
options considered by the EPA.
The EPA considered, but rejected, a definition based on a narrow
interpretation that would include only valves and fittings on a well as
being associated equipment primarily because this option would not
provide any additional relief to industry beyond what would have been
provided had Congress only used the term ``well'' in section 112(n)(4)
of the Act. The EPA also rejected a definition, initially recommended
by industry, that was based on a broad interpretation that would
include equipment far beyond the well as associated equipment.
In discussions with industry stakeholders over an extended period
of time prior to proposal, the Agency sought to reach a workable
solution on the definition of associated equipment, one that recognized
the need to implement relief for this industry as Congress intended,
and that also allowed for the appropriate regulation of significant
emission points. In a technical evaluation, the EPA identified glycol
dehydration units and storage tanks with flash emission potential as
substantial contributors to HAP emissions, particularly relative to
sources such as production wells. This conclusion was supported by
industry. Under the proposed approach, associated equipment was defined
as all equipment up to the point of custody transfer, excluding glycol
dehydration units and storage vessels with the potential for flash
emissions. This approach also included a definition of facility in the
rule that effectively limited the distance over which all emission
points (including glycol dehydration units and storage vessels with the
potential for flash emissions) may be aggregated. Based on discussions
with industry prior to proposal, as well as comments received
supporting the proposed definition of associated equipment, the Agency
believes that the proposed approach
[[Page 32620]]
best meets both industry and EPA goals for implementation of the
language of section 112(n)(4).
Commenters who argued that the Agency exceeded its authority with
the definition of associated equipment offered no substantive new
information to support their claim. The EPA could not find support in
the statute or in the legislative history that indicated that Congress
intended to preclude aggregation of all emission points, including such
significant ones as glycol dehydration units and storage tanks with
flash emission potential through their inclusion as associated
equipment. Rather, there are clear indications, in the EPA's judgement,
that Congress' primary intent was to preclude the aggregation of small
emitting sources over vast distances. The legislative history of the
Act, for example, indicates that Congress believed that oil and natural
gas production wells and their ``associated equipment'' generally have
low HAP emissions, and are typically located in widely dispersed
geographic areas, rather than being concentrated in a single area. The
EPA used this background as a guide in developing an interpretation of
``associated equipment'' along with available data on HAP emissions
from emission points within the oil and natural gas production source
category. The EPA believes that glycol dehydration units and storage
vessels with the potential for flash emissions are not the type of
small HAP emission points that Congress intended to be included in the
definition of associated equipment.
After the EPA's review and consideration of all comments received
on the proposal, the definition of associated equipment promulgated in
today's rule is the same as proposed.
C. Applicability
1. Black Oil Definition
In the proposed subpart HH, the EPA provided an exemption from the
subpart for facilities that exclusively handle black oil. Black oil was
defined in subpart HH as a hydrocarbon liquid with an API gravity less
than 40 degrees and a GOR less than 0.31 m3/liter of liquid.
Several commenters questioned the EPA's basis for the black oil
definition. The commenters requested that the EPA revise the GOR and
API gravity cutoffs. One commenter stated that it was unclear whether
the definition of black oil, with the proposed cutoffs, was a
determination related to human health risk.
During the development of the proposal, representatives of the oil
and natural gas production industry stressed that their industry was
composed of large numbers of facilities that handle black oil, and that
black oil was not a significant contributor to overall source category
HAP emissions. The EPA reviewed the available information and agreed
with the industry representatives that facilities that exclusively
handle black oil are not significant contributors to overall HAP
emissions from the source category. Furthermore, the EPA did not
identify control technologies, designed to reduce HAP, in use at
existing facilities that exclusively process, handle, or store black
oil. Therefore, the EPA determined that the MACT floor for black oil
facilities was no control. This determination was not made based on the
health risks associated with black oil.
The EPA developed the proposed definition of black oil based on a
series of technical articles that describe five basic hydrocarbon
fluids that typically exist in a reservoir: black oil, volatile oil,
retrograde gas, wet gas, and dry gas (Air Docket A-94-04). Of these,
black oil and volatile oil exist as liquid in the reservoir. Black oil,
which is a mixture of chemical species ranging from methane to large,
heavy, nonvolatile organic molecules, is in solution with dry gas,
which is primarily methane. Volatile oil, which contains fewer heavy
molecules, is in solution with retrograde gas, which has fewer of the
heavy organic molecules.
According to these articles, reservoir fluid types are determined
by rules-of-thumb based on an initial producing GOR, stock-tank liquid
gravity, and stock tank liquid color. In particular, fluid type is
usually determined by initial producing GOR and confirmed by stock tank
gravity values and stock tank color. (Note: The distinction between
initial producing GOR and producing GOR is important. As reservoir
pressure reduces over time, the producing GOR for black oil increases.
Therefore, if any other GOR is used, the facility may not appear to
qualify for the exemption.) The rule-of-thumb for volatile oil is an
initial producing GOR of 0.31 m\3\/liter. Volatile oil is also
suspected if the API gravity is equal to or greater than 40 degrees and
a color that is brown, reddish, orange, or green. The rule-of-thumb for
black oil is an initial producing GOR less than 0.31 m\3\/liter, an API
gravity of less than 45 degrees, and a color that is dark, usually
black (sometimes with a greenish cast) or brown.
Since color determination is subjective, the EPA selected initial
producing GOR and API gravity as quantifiable criteria for defining
black oil. In addition, since there is a gap between the rule-of-thumb
API gravity criteria for black oil and volatile oil, the EPA selected
the lower, more conservative value of 40 degrees. The EPA believes that
using a higher API gravity to define black oil, such as 45 or 50
degrees as recommended by the commenters, would increase the
possibility that the liquid is a volatile oil, thus exempting sources
that are likely to have higher HAP emissions. The EPA believes that the
criteria for defining a black oil, which were obtained directly from
widely recognized definitions of black oil and volatile oil used in the
oil and natural gas industry, are technically sound for identifying
which sources are included as black oil facilities. Therefore, the EPA
has not modified the black oil definition.
2. Potential-to-Emit
Several commenters were concerned with the methods used to
determine whether or not a facility was a major source. In particular,
the EPA received several comment letters regarding the calculation of a
facility's potential-to-emit (PTE) when determining a facility's major
source status. The EPA received comments regarding the calculation of
PTE on the following issues: (1) potential emissions calculated to
determine major source status should consider controls and operational
limitations whether or not they are federally enforceable as specified
in the National Mining Congress v. EPA (59 F.3d.1351, D.C. Cir. 1995)
court case; (2) potential emissions should not be based on equipment
operating capacity because it would result in overregulation, but
should consider the inherent operating limitations of the facility
(e.g., declining production levels over time); (3) the EPA should
provide a simplified approach to calculate PTE, which takes into
account design and operational limitations; and (4) the EPA should use
the logic in the PTE Transition policy where sources with low emissions
may be considered nonmajor if records of actual emissions are
maintained.
a. Use of Limitations in Calculating PTE. The EPA received comments
requesting that potential emissions calculated to determine major
source status should consider controls and operational limits whether
or not they are federally enforceable.
The EPA believes that by referring to the definition of PTE in
Sec. 63.2 of subpart A, subparts HH and HHH contain the provisions for
accounting for control
[[Page 32621]]
devices and federally enforceable operating limitations as requested by
the commenters.
With respect to the National Mining court case, the court required
the EPA to reconsider the Federal enforceability requirement, but did
not vacate the requirement. As a result, the requirement for Federal
enforceability is still in effect. The definition of PTE for the NESHAP
program (40 CFR 63.2) is currently under review, and the EPA is engaged
in a rulemaking process to amend the requirements in the General
Provisions. The EPA has not modified subparts HH and HHH in response to
these comments.
b. Use of Inherent Design and Operational Limitations in
Calculating PTE. Several commenters were concerned that PTE estimates,
as defined in the General Provisions, would be unrealistically high and
would subject many small insignificant sources to the NESHAP
requirements. The commenters requested that PTE be based on the
inherent design and operational limitations of production and
transmission and storage facilities, such as throughput rates.
According to commenters, the throughput of oil and natural gas
production operations declines over time, and existing equipment is
often designed, constructed and operated based on high initial
production rates. Therefore, the commenters suggested that the
facilities are usually operated at actual throughput rates that are
much lower than the design capacities.
The EPA agrees that there are certain inherent throughput
limitations associated with the production of oil and natural gas,
primarily related to declining production rates. Therefore, the final
subpart HH specifies a method for calculating maximum facility
throughput to determine major source status and applicability to
subpart HH. This method is based on a facility's past production rate
and ability to document declining annual operations. However, it is the
responsibility of the owner or operator to be aware of changes that
could require a facility to recalculate its PTE and to do so in a
timely manner. The owner or operator could be found in violation back
until the point in time at which an engineering judgement would have
shown that the facility was reasonably capable of emitting at major
source thresholds. A detailed discussion is presented in section 2.1.1
of the BID volume 2.
The EPA also received comments that the EPA should consider the
seasonal operation of natural gas storage facilities in estimating
potential emissions, and that the facility's PTE cannot be based on
withdrawal for the entire season at maximum capacity. The commenters
explained that natural gas storage facilities must spend part of the
year injecting gas, and that withdrawal rates decrease as the storage
field's pressure drops.
The EPA agrees that natural gas storage facilities have inherent
limitations due to the nature of their operations. Therefore, the final
rule (subpart HHH) contains a method for calculating maximum facility
throughput to determine major source status and applicability of
subpart HHH. The method is based on the maximum withdrawal and
injection rates and the working gas capacity for a given storage field.
A more detailed discussion is presented in section 2.1.1 of BID volume
2.
c. Simplified Approach to Calculate PTE. Several commenters
recommended a simplified approach to calculating PTE, such as screening
equations similar to those developed for other NESHAP, to take into
account design and operational limitations.
The EPA evaluated the use of an equation similar in structure to
the Gasoline Distribution NESHAP, 40 CFR part 63, subpart R. After
extended effort, the EPA found that the number of variables was too
extensive to allow development of a manageable equation. The EPA also
received supplemental comments from industry and trade associations
indicating that their efforts in developing such an equation resulted
in the same outcome (Air Docket A-94-04).
Therefore, as an alternative, the EPA developed a simplified major
source determination (MSD) for HAP emission sources in the oil and
natural gas production and natural gas transmission and storage source
categories. The simplified MSD allows the owner or operator of a
facility to easily determine (1) if they are major sources and whether
NESHAP requirements apply to their facility, and (2) if they are
required to obtain a title V operating permit.
Therefore, the final subpart HH states that facilities, prior to
the point of custody transfer, that have a facilitywide actual annual
average natural gas throughput less than 18.4 thousand m3/
day and a facilitywide actual annual average hydrocarbon liquid
throughput less than 39,700 liter/day are exempt from subpart HH. A
more detailed discussion on the development of this MSD is presented in
section 2.1.1 of the BID volume 2.
Owners and operators of production facilities, after the point of
custody transfer (including natural gas processing plants), must
aggregate emissions from all HAP emissions units at the facility when
determining whether or not the facility is a major source. Production
facilities, after the point of custody transfer, are likely to have
emission units in addition to glycol dehydration units and storage
vessels, such as amine treaters and sulfur recovery units that are
typically located at natural gas processing plants. Since these
emissions units must be included in the total emissions for the
facility, the EPA could not develop a cutoff that would reasonably
ensure that sources operating below such a cutoff would not be major
sources. Therefore, production facilities located after the point of
custody transfer, including natural gas processing plants, do not
qualify for the simplified major source determination.
Using the same procedure, the EPA developed an MSD for natural gas
transmission and storage facilities where glycol dehydration units are
the only HAP emission points. The final subpart HHH states that natural
gas transmission and storage facilities operating with an actual annual
average natural gas throughput below 28.3 thousand m3/day
are exempt from subpart HHH.
d. Use of PTE Transition Policy. Under the EPA's 1995 Potential to
Emit Transition Policy, sources with low emissions (e.g., less than 50
percent of major source thresholds) may be deemed nonmajor if records
of actual emissions are kept. Several commenters suggested the use of
written documentation of physical and operational limitations that
would be federally, State, or otherwise practically enforceable.
In the January 25, 1995 policy memorandum entitled ``Options for
Limiting the Potential to Emit (PTE) of a Stationary Source Under
Section 112 and Title V of the Clean Air Act (Act),'' the EPA issued a
transition policy for section 112 and title V. The transition policy
addressed concerns that some sources may face gaps in the ability to
acquire federally enforceable PTE limits because of delays in State
adoption or EPA approval of programs or in their implementation. In
order to ensure that such gaps would not create adverse consequences
for States or for sources, the EPA provided that, during a 2-year
period extending from January 1995 through January 1997, sources
lacking federally enforceable limitations, State and local air
regulators had the option of treating the following types of sources as
non-major under section 112 and in their title V programs: (1) sources
that maintain adequate records to demonstrate that their actual
emissions
[[Page 32622]]
are less than 50 percent of the applicable major source threshold and
have continued to operate at less than 50 percent of the threshold
since January 1994, and (2) sources with actual emissions between 50
and 100 percent of the major source threshold but which hold State-
enforceable limits that are enforceable as a practical matter. On
August 27, 1996, the transition policy was extended until July 31,
1998. On July 10, 1998, in a memorandum entitled ``Second Extension of
January 25, 1995 Potential to Emit Transition Policy and Clarification
of Interim Policy,'' the EPA announced a second extension of the
transition policy. The extensions were provided because the EPA is
engaged in a rulemaking process to consider amendments to the current
PTE requirements. Currently, the PTE rulemaking, which will address the
PTE requirements in the General Provisions (40 CFR part 63, subpart A)
and the title V operating permits program, has not been completed.
Those rule amendments will affect federal enforceability requirements
for PTE limits under these programs. Thus, there will continue to be
uncertainty with respect to federally enforceable limits. Therefore, in
the July 10, 1998 memorandum, the EPA extended the transition policy
until December 31, 1999, or until the effective date of the final rule
in the PTE rulemaking, whichever is sooner.
The EPA expects that the rulemaking will be completed before
December 31, 1999, and owners and operators will have the option of
complying with the PTE rulemaking as well as the procedures specified
in subparts HH and HHH.
D. Glycol Dehydration Unit Process Vent Standards
The proposed standards required a 95.0 percent control efficiency
for all control devices, but did not specify over which averaging
period the 95.0 percent should be determined. By not specifying an
averaging period, the proposed rule required continuous compliance for
all control devices. The EPA received several comment letters
requesting that the EPA specify an averaging period. The commenters
were particularly concerned that condensers could not achieve a 95.0
percent control efficiency on a continuous basis and that additional
controls would be required to ensure compliance with the 95.0 percent
requirement.
The commenters' primary point was that condensers are significantly
affected by changes in ambient temperature. According to the
commenters, when the ambient temperature is high, the condensers are
less efficient. The commenters were concerned that during the warm
summer months, condensers would not meet the control requirements.
Therefore, the commenters specifically requested either a 30-day or a
12-month averaging period for compliance with the control requirements
to balance changes in ambient temperature. In support of this request,
the commenters maintained that using a longer averaging period would
create no significant change in the emissions to the environment, but
would substantially decrease the number of technical violations of the
standard and reduce the administrative burden for the industry and the
EPA.
The EPA reviewed the control efficiency and averaging period
requirements in response to these comments. Based on the Agency's
review of the possible options, today's rules require 95.0 percent
control as a daily average. As an alternative for owners or operators
that install condensers, the EPA has modified subpart HH to allow 95.0
percent condenser control as a 365-day rolling average, based on daily
average condenser efficiency as a function of condenser outlet
temperature (i.e., at the end of each operating day, the owner or
operator calculates the daily average condenser outlet temperature,
then calculates the 365-day average control efficiency for the
preceding 365 days, including the current operating day).
Based on the information collected under the authority of section
114 of the Act, the comments received during the public comment period,
and site visits, the EPA believes that an averaging period shorter than
365 days is appropriate for the natural gas transmission and storage
source category. To the Agency's knowledge, glycol dehydration units
located at storage facilities do not typically operate throughout the
year. Therefore, the EPA was concerned that it would take more than 1
calendar year for a facility to obtain 365 days of data. Additionally,
glycol dehydration units located at these sources do not typically
operate during the warm summer months when condenser efficiency is
lower. Although transmission facilities do operate for most of the
year, the EPA believes that the HAP emission units in operation at
these facilities are primarily compressors, and that most glycol
dehydration units located at these facilities are used for withdrawing
natural gas from storage (i.e., not likely to operate year-round).
Therefore, for condensers installed on glycol dehydration units subject
to control requirements under subpart HHH, the EPA has modified the
requirements to specify that owners or operators that install
condensers have the option of meeting a 95.0 percent control efficiency
as a 30-day rolling average.
Several commenters requested that the EPA allow for combinations of
controls and process modifications to achieve the required control
efficiency. The commenters provided several suggestions for modifying
the language in Sec. 63.765(c)(2) stating that the owner or operator
could reduce emissions from the glycol dehydration unit by 95.0 percent
through process modifications or process modifications with controls.
In addition, one of the suggestions was to include language allowing
the owner or operator to complete a one-time compliance demonstration
for the process modification.
The EPA agrees that owners or operators should be allowed to
achieve a 95.0 percent emission reduction using process modifications
or combinations of process modifications and one or more control
devices. Therefore, today's rules contain requirements for
demonstrating compliance with a 95.0 percent emission reduction using
process modifications or a combination of process modifications and one
or more control devices. In particular, the final rule requires the
owner or operator to demonstrate how emissions have been reduced and to
what level, and that the facility continues to be operated such that
the 95.0 percent emission reduction is maintained.
The EPA does not believe that a one-time compliance demonstration
would ensure future or continuous compliance, and the EPA believes that
it is not appropriate. Therefore, the EPA has not included the
commenter's suggested language allowing a one-time compliance
demonstration for process modification. Instead, the final rules
require the owner or operator to document facility operations and to
provide this information in the Periodic reports.
E. Storage Vessel Standards
The criteria for an API gravity equal to or greater than 40 degrees
or an initial producing GOR equal to or greater than 0.31 m3/liter were
used in the proposed rule to define storage vessels with the potential
for flash emissions. Prior to proposal, the EPA's analysis of storage
vessels that contain hydrocarbon liquids that have an API gravity or an
initial producing GOR higher than these criteria indicated the
potential for significant flash emissions.
[[Page 32623]]
The EPA received comment letters objecting to the proposed cutoffs
for storage vessels with the potential for flash emissions. In order to
demonstrate their objection to the technical basis for these exemption
criteria, the commenters provided emissions estimates for tanks
containing hydrocarbon liquids with an API gravity less than 40 degrees
and GOR of less than 0.31 m3/liter. According to the
emission estimates, these tanks, which do not meet the criteria for a
storage vessel with the potential for flash emissions and would be
exempt from the storage vessel control requirements, had significant
HAP emissions. The EPA also received emission estimates for a tank
containing a hydrocarbon liquid with an API gravity greater than 40
degrees and a GOR greater than 0.31 m3/liter. According to
the analysis provided by the commenter, this tank would be subject to
the storage vessel control requirements but had no flash emissions.
The commenters did not provide alternative suggestions for defining
storage vessels with the potential for flash emissions, other than
recommending that ``the proposed storage tank exemption/control
criteria be based on credible engineering methods supported by
fundamental principles of fluid phase behavior.''
The EPA developed the definition for storage vessels with the
potential for flash emissions based on criteria (i.e., API gravity and
GOR) that were easily recognized by industry personnel and relatively
easy to obtain. Furthermore, these criteria are based on hydrocarbon
liquid characteristics.
According to section 112(d)(1), the Administrator is required to
establish emission standards for each category of major sources.
Section 112(d)(1) states that ``[T]he Administrator may distinguish
among classes, types, and sizes of sources within a category or
subcategory in establishing such standards * * *.'' Furthermore,
section 112(d)(3) states that emission standards for existing sources
in a category may be no less stringent than the MACT floor.
As stated in section V.C.1 of this preamble, the EPA has
established that among the class of sources referred to as black oil
facilities, the MACT floor is no control. For the class of sources
defined as storage vessels with the potential for flash emissions
(which includes storage vessels that do not process black oil), the EPA
evaluated `` * * * the average emission limitation achieved by the best
performing 12 percent of the existing sources (for which the
Administrator has emissions information) * * * '' (section 112(d)(3)(A)
of the Act). The EPA determined that the top 12 percent of existing
storage vessels with the potential for flash emissions were controlled.
The EPA recognizes that there could be specific situations, such as
the ones analyzed by the commenters, where emissions of an exempted
stream are higher than those of a non-exempted stream. In addition,
there are many factors that affect whether flash emissions occur (e.g.,
pressure drop between two tanks, liquid vapor pressure, etc.). However,
the EPA believes that this approach identifies hydrocarbon liquids that
have a potential for significant flash emissions under conditions
representative of industry operations.
In today's rule (final subpart HH), the EPA has added the
throughput cutoff criterion to the storage vessels with the potential
for flash emissions definition. The final rule states that a storage
vessel with the potential for flash emissions is defined as a storage
vessel that contains a hydrocarbon liquid with a stock tank GOR equal
to or greater than 0.31 m3/liter and an API gravity equal to or greater
than 40 degrees, and an actual annual average hydrocarbon liquid
throughput equal to or greater than 79,500 liter/day. By adding the
throughput criterion to the definition of storage vessels with the
potential for flash emissions, rather than as a cutoff specified in
proposed Sec. 63.764(c)(2), storage vessels that do not meet the
criteria for a storage vessel with the potential for flash emissions
are not considered affected sources in the final rule and are not
included in a facility's PTE calculation for determining major source
status. The EPA believes that based on representative industry
operations, the 40 degrees, 0.31 m3/liter and the 79,500-
liter/day exemption criteria are appropriate for defining storage
vessels with the potential for flash emissions.
F. Standards for Natural Gas Transmission and Storage
The EPA received several comment letters expressing concern for the
EPA's proposed standard for the natural gas transmission and storage
source category. The commenters stated that the EPA did not have
sufficient data to develop standards for the natural gas transmission
and storage source category. The commenters requested that the EPA
delay the natural gas transmission and storage portion of the proposed
rulemaking to properly survey the industry for more meaningful data and
assess whether a standard for the natural gas transmission and storage
source category is necessary or achievable.
Several commenters explained that a review of the background
information for proposed subpart HHH showed that the database consisted
of information on the methods used in natural gas transmission from
only two companies and no underground storage facilities. The
commenters noted that the companies surveyed were predominately oil
production facilities that handled gas as a by-product of oil
production and that have higher HAP emissions because they handle more
liquids with higher concentrations of HAP.
In response to these comments, the EPA collected additional data on
glycol dehydration units in the natural gas transmission and storage
source category through site visits and requests for information under
the authority of section 114 of the Act.
Through these site visits and survey questionnaires, the EPA
collected information from 83 facilities in the natural gas
transmission and storage source category. The EPA considered this new
information, along with the previously collected information on the
natural gas transmission and storage source category, in developing a
MACT floor for existing and new process vents on glycol dehydration
units located at facilities in this source category. The EPA also used
this information to better characterize processes and operations at
natural gas transmission and storage facilities.
As stated in the January 15, 1999 supplemental notice (64 FR 2611),
the additional data supported a MACT floor of 95.0 percent for existing
and new natural gas transmission and storage facilities. In addition,
the EPA announced that the Agency was considering raising the proposed
throughput cutoff of 85 thousand
m3/day to 283 thousand m3/day on an actual annual
average basis. Glycol dehydration units operating below this cutoff
would not be required to install controls under subpart HHH. The data
did not warrant a change in the benzene emission cutoff of 0.90 Mg/yr.
The public comment period closed on February 16, 1999. The EPA
received four comment letters in response to the EPA's request for
comments and supporting information on the consideration of a 95.0
percent HAP emission reduction as the floor level of control, on the
283 thousand m3/day natural gas throughput cutoff and the
0.90-Mg/yr benzene emission cutoff. The commenters agreed that
exempting glycol dehydration units with actual annual average natural
gas throughputs
[[Page 32624]]
less than 283 thousand 78m3/day and with actual average
benzene emissions less than 0.90 Mg/yr from the control requirements
under subpart HHH was appropriate.
However, the commenters indicated that they did not agree with a
MACT floor of 95.0 percent for the transmission and storage source
category. The commenters requested that the final rule should either
exempt existing sources controlled by condensers, or require that
existing sources controlled with condensers be controlled to a
different level (i.e., 70 percent) than the combustion technology-based
MACT floor. The commenters stated that condensers could consistently
achieve a 75 percent emission reduction and that requiring an
additional 20 percentage points of emission reduction in HAP would be
inconsistent with the cost-to-benefit analysis in the February 6, 1998
proposal.
The EPA does not believe that it is necessary to provide exemptions
or alternative levels of control for existing glycol dehydration units
that are controlled by condensers. The EPA believes that this would not
be consistent with the Act, which specifies in section 112(d)(3) that
for a source category with 30 or more sources (such as the transmission
and storage source category), the MACT floor for existing sources shall
not be less stringent than `` * * * the average limitation achieved by
the best performing 12 percent of the existing sources * * *.'' The
data collected by the EPA indicated that the average limitation
achieved by the top 12 percent of the existing glycol dehydration units
located at natural gas transmission and storage facilities was 95.0
percent. Furthermore, the data indicated that the top 12 percent of the
existing glycol dehydration units were controlled using combustion or a
combination of combustion and condensation. Therefore, in accordance
with the statute, the EPA established the MACT floor to be 95.0 percent
for glycol dehydration units located at natural gas transmission and
storage facilities, which corresponds to combustion.
However, the EPA agrees that the supplemental notice did not
address the issue of averaging period for condensers in use at
transmission and storage facilities. As stated in this preamble, the
final rule allows an owner or operator that installs a condenser for
control of HAP from glycol dehydration unit process vents to establish
compliance with the 95.0 percent HAP emission reduction on a 30-day
rolling average. In addition, the final rule allows the owner or
operator to comply with one of the following: (1) 95.0 percent HAP
emission reduction, (2) 20 ppmv outlet HAP concentration for combustion
devices, or (3) outlet emissions of 0.90 Mg/yr of benzene. The EPA
believes that the 0.90 Mg/yr benzene emission limit and the 30-day
averaging period for condensers provides sufficient flexibility for
owners and operators of existing controlled glycol dehydration units. A
more detailed discussion regarding the EPA's responses to the comments
received on the supplemental notice are presented in the BID volume 2.
G. Monitoring, Recordkeeping, and Reporting Requirements
The EPA received several comment letters claiming that the
recordkeeping and reporting requirements of the proposed rule were
extremely burdensome. The commenters requested that the EPA reduce the
monitoring, recordkeeping, and reporting burden associated with the
proposed rule. In particular, commenters were concerned that remote and
unmanned facilities would be overburdened by the proposed monitoring,
recordkeeping and reporting requirements. Commenters also requested
that provisions be added to the rule to avoid duplicative reporting.
Other commenters requested that flexibility to allow alternative
monitoring, recordkeeping, and reporting be incorporated into the final
rule.
The EPA recognizes that unnecessary monitoring, recordkeeping, and
reporting requirements would burden both the source and enforcement
agencies. Prior to proposal, the EPA attempted to reduce the amount of
monitoring, recordkeeping, and reporting to only that which is
necessary to demonstrate compliance.
Although the EPA has not removed the monitoring requirements for
unmanned or remote facilities, the EPA did evaluate the possibility of
reducing the requirements for unmanned facilities. The EPA concluded,
however, that the monitoring requirements are the minimum necessary to
ensure that control devices are operating to ensure compliance.
The EPA reevaluated whether monitoring, recordkeeping, and
reporting requirements could be further reduced while maintaining the
enforceability of the rule. Therefore, the EPA has made the following
changes in the promulgated rule to further reduce the monitoring,
recordkeeping, and reporting burden.
(1) Almost all reports have been consolidated into the Notification
of Compliance Status report and the Periodic reports.
(2) If multiple tests are conducted for the same kind of emission
point, using the same test method, only one complete test report is
required to be submitted along with the summaries of the results of
other tests.
(3) Site-specific test plans describing quality assurance in
Sec. 63.7(c) of 40 CFR part 63, subpart A, are not specifically
required in the individual subparts because the test methods cited in
subparts HH and HHH already contain applicable quality assurance
protocols. It should be noted that the Administrator would still have
the authority to request a test plan.
(4) Periodic reports are required to be submitted semiannually for
all facilities (the proposal required quarterly reports if monitored
parameters were out of range more than a specified percentage of time).
(5) A reduction in the record retention requirements for monitored
parameters. The proposal required values of monitored parameters to be
recorded every 15 minutes and all 15-minute records had to be retained.
The final rule requires monitored parameters to be recorded every hour
and all hourly records to be retained.
Several commenters were concerned with the provisions specifying
the accuracy of the measurement devices used to comply with the subpart
and requested that the EPA change or remove the accuracy requirements.
The EPA believes that accuracy requirements are necessary to
demonstrate ongoing compliance. Furthermore, if the accuracy
requirements were removed, additional recordkeeping and reporting
requirements would be necessary to ensure that less accurate monitors
were not installed after the performance tests. However, the EPA agrees
with the commenters that the accuracy levels could be slightly less
restrictive. Therefore, the EPA has changed the accuracy levels from
1 percent of the temperature being monitored, in
oC or 0.5 oC, to 2
percent of the temperature being monitored, in oC or
2.5 oC, whichever is greater.
H. Cost and Economic Impacts
The EPA specifically requested comments on the cost impact and the
production recovery credits as discussed in section IV of the preamble
to the proposal (63 FR 6297), along with supporting documentation. The
EPA received comment letters stating that the EPA had underestimated
the costs of controls, had underestimated the cost of treating produced
water, and had
[[Page 32625]]
overstated the quantity of product recovered that could be sold to
offset the costs associated with subpart HH. Of specific concern was
the closure of smaller facilities due to the rule.
The EPA based its cost estimates for control devices on published
installed control system costs from the Ventura County (California) Air
Pollution Control District (APCD) (Air Docket A-94-04). These costs
were associated with a glycol dehydration unit regulation issued by the
Ventura County APCD. According to this information, the cost of
installing a condenser control system does not vary significantly based
on the size (capacity) of a glycol dehydration system.
Approximately 20 billion barrels per year of produced water are
generated by the oil and natural gas production source category (Air
Docket A-94-04). Using an emission model developed by the Gas Research
Institute (GRI-GLYCalc, version 3.0) to determine the amount of
produced water generated by the number of facilities estimated to be
affected by subpart HH, the EPA calculated that the oil and natural gas
production NESHAP would result in an increase in produced water
production of approximately 590,000 barrels per year. A GRI report (GRI
Publication Number GRI-96/0049) indicated that produced water would be
typically handled along with other produced water streams, either by
underground injection control, surface impoundment, or other
miscellaneous methods. Thus, the EPA believes that the final NESHAP
would have a minimal impact on existing produced water disposal costs
and that the estimated NESHAP control costs are, therefore, reasonable.
The EPA based its national cost estimate impacts on the estimated
number of facilities that would be impacted by the regulatory
provisions of subparts HH and HHH, along with detailed emission control
cost estimates per HAP emission point (Air Docket A-94-04). In
addition, the monitoring, recordkeeping, and reporting (MRR) costs were
based on a detailed analysis of the regulatory requirements of subparts
HH and HHH. The EPA currently believes that the MRR cost estimates
accurately reflect the estimated effort required to address MRR
requirements in the final NESHAP.
Further, the EPA expects that the 85 thousand m3/day
size cutoff will prevent the premature closure of a large number of
small and often marginal well operations. Not accounting for this size
cutoff would contribute to differences in the estimated reduction in
natural gas production and employment losses associated with the
standards.
As described in Section 4 of the economic impact analysis report,
the EPA's economic model determines production and closure decisions on
the basis of a producing field (i.e., a group of similar wells) that is
consistent with commenters concerns that ``production decisions are
made on a well-by-well or project basis and if an individual project's
profits fall below its break-even point, that the well will be
abandoned.'' The EPA did not estimate losses of economically producible
natural gas reserves. The economic analysis conducted by the EPA is
unable to address possible impacts on production from future natural
gas reserves. However, based on the negligible impact on current
natural gas production associated with the EPA's engineering estimate
of compliance cost, it is not expected that these impacts would be as
great as indicated by the commenter.
VI. 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 these rulemakings. The principal purposes of
the docket are (1) to allow interested parties a means to 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 texts, BID
volumes 1 and 2, references not readily available to the public, and
technical memoranda documenting the information considered by the EPA
in the development of the 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 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. 1788.02 and 1789.02) and copies may be obtained from Sandy Farmer,
OPPE Regulatory Information Division; U.S. Environmental Protection
Agency (2137); 401 M Street, SW; Washington, DC 20460 or by calling
(202) 260-2740. The information requirements are not effective until
OMB approves them.
Information is required to ensure compliance with the provisions of
the final rules. If the relevant information were collected less
frequently, the EPA would not be reasonably assured that a source is in
compliance with the final rules. In addition, the EPA's authority to
take administrative action would be reduced significantly.
The final rules require that facility owners or operators retain
records for a period of 5 years, which exceeds the 3 year retention
period contained in the guidelines in 5 CFR 1320.6. The 5 year
retention period is consistent with the provisions of the General
Provisions of 40 CFR part 63, and with the 5 year records retention
requirement in the operating permit program under title V of the Act.
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 part 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
are 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 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 final 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
484 existing and new (projected) respondents.
The estimated annual average hour burden for the final natural gas
transmission and storage NESHAP is 30 hours per respondent. The
estimated annual average cost of this burden is $1,300 for each of the
estimated 7 existing respondents.
Reports are required on a semiannual basis 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
[[Page 32626]]
for a Federal agency. This includes the time needed to review
instructions; to 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; to adjust the existing ways to comply with any
previously applicable instructions and requirements; to train personnel
to be able to respond to a collection of information; to search data
sources; to 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.
The EPA is amending the table in 40 CFR part 9 of currently approved
ICR control numbers issued by OMB for various regulations to list the
information requirements contained in these final rules.
C. Executive Order 12866: A Significant Regulatory Action Determination
Under Executive Order 12866, ``Regulatory Planning and Review,''
(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.
Pursuant to Executive Order 12866, OMB has reviewed these rules.
Changes made in response to OMB suggestions or recommendations are
documented in the public record.
D. Regulatory Flexibility Act
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 final 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 the control requirements of the oil and natural
gas production NESHAP those glycol dehydration units located at major
sources with (1) an actual flowrate of natural gas to the glycol
dehydration unit less than 85 thousand m3/day, on an annual
average basis, or (2) benzene emissions less than 0.90 Mg/yr. Also,
these considerations include exempting from the control requirements of
the natural gas transmission and storage NESHAP those glycol
dehydration units located at major sources with (1) an actual flowrate
of natural gas to the glycol dehydration unit less than 283 thousand
m3/day, on an annual average basis; or (2) benzene emissions
less than 0.90 Mg/yr.
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 1
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 1 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).
E. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. The EPA will submit a report containing this rule and
other required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is not a ``major rule'' as defined by 5 U.S.C.
804(2). This rule will be effective June 17, 1999.
F. Unfunded Mandates Reform Act
Title II of the Unfunded Mandate Reform Act of 1995 (UMRA), Pub. L.
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 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 1 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
[[Page 32627]]
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 today's final rules do not include a
Federal mandate that may result in expenditures of $100 million of more
for State, local, and tribal governments, in the aggregate, or the
private sector in any 1 year. Therefore, the requirements of the
Unfunded Mandates Reform Act do not apply to today's final rules.
G. Executive Order 12875: Enhancing the Intergovernmental Partnership
Under Executive Order 12875, the EPA may not issue a regulation
that is not required by statute and that creates a mandate upon a
State, local or tribal government unless the Federal government
provides the funds necessary to pay the direct compliance costs
incurred by those governments, or the EPA consults with those
governments. If the EPA complies by consulting, Executive Order 12875
requires the EPA to provide OMB a description of the extent of the
EPA's prior consultation with representatives of affected State, local
and tribal governments, the nature of their concerns, copies of any
written communications from the governments, and a statement supporting
the need to issue the regulation. In addition, Executive Order 12875
requires the EPA to develop an effective process permitting elected
officials and other representatives of State, local and tribal
governments to provide meaningful and timely input in the development
of regulatory proposals containing significant unfunded mandates.
Today's rules do not create a mandate on the State, local or tribal
governments. These rules do not impose any enforceable duties on these
entities. Accordingly, the requirements of Section 1(a) of Executive
Order 12875 do not apply to these rules. The EPA, nevertheless,
involved State and local governments in their development of the final
rules.
H. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
Executive Order 13045, ``Protection of Children from Environmental
Health Risks and Safety Risks,'' (62 FR 19885, April 23, 1997) applies
to any rule that: (1) the EPA determines is economically significant as
defined under Executive Order 12866, (2) concerns an environmental
health or safety risks, and (3) the EPA has any reason to believe may
disproportionately affect children. If the regulatory action meets
these criteria, the EPA must evaluate the environmental health or
safety effects of the planned rule on children, and explain why the
planned regulation is preferable to other potentially effective and
reasonably feasible alternatives considered by the EPA.
The EPA interprets Executive Order 13045 as applying only to those
regulatory actions that are based on health or safety risks, such that
the analysis required under section 5.501 of the Order has the
potential to influence the regulation. These rules are not subject to
Executive Order 13045 for two reasons: (1) the rule is based solely on
technology performance; and (2) no alternative technologies have been
identified that would provide greater stringency at a reasonable cost,
therefore, an assessment of impacts on children would have no impact on
the stringency decision.
I. Executive Order 13084: Consultation and Coordination With Indian
Tribal Governments
Under Executive Order 13084, the EPA may not issue a regulation
that is not required by statute, that significantly or uniquely affects
the communities of Indian tribal governments, and that imposes
substantial direct compliance costs on those communities unless the
Federal Government provides the funds necessary to pay the direct
compliance costs incurred by the tribal governments, or the EPA
consults with those governments. If the EPA complies by consulting,
Executive Order 13084 requires the EPA to provide to OMB, in a
separately identified section of the preamble to the rule, a
description of the extent of the EPA's prior consultation with
representatives of affected tribal governments, a summary of the nature
of their concerns, and a statement supporting the need to issue the
regulation. In addition, Executive Order 13084 requires the EPA to
develop an effective process permitting elected officials and other
representatives of Indian tribal governments ``to provide meaningful
and timely input in the development of regulatory policies on matters
that significantly or uniquely affect their communities.''
Today's rules do not significantly or uniquely affect the
communities of Indian tribal governments. The final rules do not create
mandates upon tribal governments. Accordingly, the requirements of
section 3(b) of Executive Order 13084 do not apply to these rules.
J. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA), Pub. L. 104-113 (March 7, 1996), directs all Federal
agencies to use voluntary consensus standards in regulatory and
procurement activities unless doing so would be inconsistent with
applicable law or otherwise impracticable. Voluntary consensus
standards are technical standards (e.g., materials specifications, test
methods, sampling procedures, and business practices) developed or
adopted by one or more voluntary consensus bodies. The NTTAA requires
Federal agencies to provide Congress, through annual reports to OMB,
with explanations when an agency does not use available and applicable
voluntary consensus standards. This section summarizes the EPA's
response to the requirements of the NTTAA for the analytical and test
methods required by this final rule.
Consistent with the NTTAA, the EPA conducted a search to identify
voluntary consensus standards. The search identified 16 voluntary
consensus standards that appeared to have possible use in lieu of EPA
standard reference methods. However, after reviewing available
standards, the EPA determined that eight of the candidate consensus
standards identified for measuring HAP or surrogate pollutant emissions
subject to the emission standards in the rule would not be practical
due to lack of equivalency, documentation, validation data and other
important technical and policy considerations. Seven of the remaining
candidate consensus standards are new standards under development that
the EPA plans to follow, review, and consider adopting at a later date.
One consensus standard, ASTM Z7420Z, is potentially practical for
EPA use in lieu of EPA Method 18 (See 40 CFR part 60, appendix A). At
the time of the EPA's search, the ASTM standard was still under
development and the EPA had provided comments on the method. The EPA
also compared a draft of this ASTM standard to methods previously
reviewed as alternatives to EPA Method 18 that were approved with
specific applicability limitations. These methods are designated as
ALT-017 and CTM-028 and available through EPA's Emission Measurement
Center Internet site at www.epa.gov/ttn/emc/tmethods.html. The proposed
ASTM Z7420Z standard is very similar to these approved alternative
methods. When finalized and adopted by ASTM, the standard may be
equally suitable for the same applications as the approved
[[Page 32628]]
alternatives. However, this rule does not adopt the ASTM standard since
it is not practical to do so until the potential candidate is final and
the EPA has review the final standard. The EPA plans to continue to
follow the progress of the standard and will consider adopting the ASTM
standard at a later date.
Similarly, the Gas Research Institute has developed a sampling
method for glycol dehydration units, the ``Atmospheric Rich/Lean Method
for Determining Glycol Dehydrator Emissions'' (GRI-95/0368.1). The
development of this procedure included a field evaluation program and
technical review by the EPA. A report documenting this procedure has
been available to the public from the GRI since 1996. This procedure
provides a simpler, cheaper, and technically appropriate means of
determining HAP emissions from glycol dehydration unit process vents
when direct measurement is necessary. Consistent with the Agency's
commitment to reduce costs to the private sector where technically
feasible and in accordance with Clean Air Act requirements, the EPA has
included the ``Atmospheric Rich/Lean Method for Determining Glycol
Dehydrator Emissions'' as an alternative control device performance
test procedure.
This rule requires standard EPA methods known to the industry and
States. Approved alternative methods also may be used with prior EPA
approval.
List of Subjects in 40 CFR Part 63
Environmental protection, Air pollution control, Hazardous air
pollutants, Black oil, Associated equipment, Storage vessels with the
potential for flash emissions, Glycol dehydration units, Oil and
natural gas production, Natural gas transmission and storage, Equipment
leaks, Natural gas processing plant, Reporting and recordkeeping
requirements.
Dated: May 14, 1999.
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 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., as amended by Pub. L. 101-
549, 104 Stat. 2399.
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 Startups, shutdowns, and malfunctions.
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 equipment requirements.
63.772 Test methods, compliance procedures, and compliance
determinations.
63.773 Inspection and monitoring requirements.
63.774 Recordkeeping requirements.
63.775 Reporting requirements.
63.776 Delegation of authority.
63.777 Alternative means of emission limitation.
63.778 [Reserved]
63.779 [Reserved]
Appendix to Subpart HH--Tables
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 and operators of the
emission points, 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) and either (a)(2) or (a)(3) of
this section.
(1) Major sources of hazardous air pollutants (HAP) as determined
using the maximum natural gas or hydrocarbon liquid throughput, as
appropriate, calculated in paragraphs (a)(1)(i) through (a)(1)(iii) of
this section. A facility that is determined to be an area source based
on emission estimates using the maximum natural gas or hydrocarbon
throughput calculated as specified in paragraphs (a)(1)(i) through
(iii) of this section, but subsequently increases emissions or
potential to emit above the major source levels (without first
obtaining and complying with other limitations that keep its potential
to emit HAP below major source levels), becomes a major source and must
comply thereafter with all applicable provisions of this subpart
starting on the applicable compliance date specified in paragraph (f)
of this section. Nothing in this paragraph is intended to preclude a
source from limiting its potential to emit through other appropriate
mechanisms that may be available through the permitting authority.
(i) If the owner or operator documents, to the Administrator's
satisfaction, a decline in annual natural gas or hydrocarbon liquid
throughput, as appropriate, each year for the 5 years prior to June 17,
1999, the owner or operator shall calculate the maximum natural gas or
hydrocarbon liquid throughput used to determine maximum potential
emissions according to the requirements specified in paragraph
(a)(1)(i)(A) of this section. In all other circumstances, the owner or
operator shall calculate the maximum throughput used to determine
whether a facility is a major source in accordance with the
requirements specified in paragraph (a)(1)(i)(B) of this section.
(A) The maximum natural gas or hydrocarbon liquid throughput is the
average of the annual natural gas or hydrocarbon liquid throughput for
the 3 years prior to June 17, 1999, multiplied by a factor of 1.2.
(B) The maximum natural gas or hydrocarbon liquid throughput is the
highest annual natural gas or hydrocarbon liquid throughput over the 5
years prior to June 17, 1999, multiplied by a factor of 1.2.
(ii) The owner or operator shall maintain records of the annual
facility natural gas or hydrocarbon liquid throughput each year and
upon request submit such records to the Administrator. If the facility
annual natural gas or hydrocarbon liquid throughput increases above the
maximum natural gas or hydrocarbon liquid throughput calculated in
paragraph (a)(1)(i)(A) or (a)(1)(i)(B) of this section, the maximum
natural gas or hydrocarbon liquid throughput must be recalculated using
the higher throughput multiplied by a factor of 1.2.
(iii) The owner or operator shall determine the maximum values for
other parameters used to calculate emissions as the maximum for the
period over which the maximum natural gas or hydrocarbon liquid
throughput is determined in accordance with paragraph (a)(1)(i)(A) or
(B) of this section. Parameters shall be based on either highest
measured values or annual average.
(2) Facilities that process, upgrade, or store hydrocarbon liquids
prior to the point of custody transfer.
(3) Facilities that process, upgrade, or store natural gas prior to
the point at which natural gas enters the natural gas
[[Page 32629]]
transmission and storage source category or is delivered to a final end
user. For the purposes of this subpart, natural gas enters the natural
gas transmission and storage source category after the natural gas
processing plant, when present. If no natural gas processing plant is
present, natural gas enters the natural gas transmission and storage
source category after the point of custody transfer.
(b) The affected sources to which the provisions of this subpart
apply 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) through (4) of this section.
(1) Each glycol dehydration unit;
(2) Each storage vessel with the potential for flash emissions;
(3) The group of all ancillary equipment, except compressors,
intended to operate in volatile hazardous air pollutant service (as
defined in Sec. 63.761), which are located at natural gas processing
plants; and
(4) Compressors intended to operate in volatile hazardous air
pollutant service (as defined in Sec. 63.761), which are located at
natural gas processing plants.
(c) [Reserved]
(d) The owner and operator of a facility that does not contain an
affected source as specified in paragraph (b) of this section are not
subject to the requirements of this subpart.
(e) Exemptions. The facilities listed in paragraphs (e)(1) and
(e)(2) of this section are exempt from the requirements of this
subpart. Records shall be maintained as required in Sec. 63.10(b)(3).
(1) 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. For the purposes of this subpart, a black
oil facility that uses natural gas for fuel or generates gas from black
oil shall qualify for this exemption.
(2) A facility, prior to the point of custody transfer, with a
facilitywide actual annual average natural gas throughput less than
18.4 thousand standard cubic meters per day and a facilitywide actual
annual average hydrocarbon liquid throughput less than 39,700 liters
per day.
(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 provisions of this subpart no later than June
17, 2002 except as provided for in Sec. 63.6(i). The owner or operator
of an area source, the construction or reconstruction of which
commenced before February 6, 1998, that increases its emissions of (or
its potential to emit) HAP such that the source becomes a major source
that is subject to this subpart shall comply with this subpart 3 years
after becoming a major source.
(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 initial startup or June 17, 1999, whichever date is
later. Area sources, the construction or reconstruction of which
commences on or after February 6, 1998, that become major sources shall
comply with the provisions of this standard immediately upon becoming a
major source.
(g) The following provides owners or operators of an affected
source with information on overlap of this subpart with other
regulations for equipment leaks. The owner or operator shall document
that they are complying with other regulations by keeping the records
specified in Sec. 63.774(b)(9).
(1) After the compliance dates specified in paragraph (f) of this
section, ancillary equipment and compressors that are subject to this
subpart and that are also subject to and controlled under the
provisions of 40 CFR part 60, subpart KKK, are 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 and compressors that are subject to this
subpart and are also subject to and controlled under the provisions of
40 CFR part 61, subpart V, are 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 and compressors that are subject to this
subpart and are also subject to and controlled under the provisions of
40 CFR part 63, subpart H, are only required to comply with the
requirements of 40 CFR part 63, subpart H.
(h) An owner or operator of an affected source that is a major
source or is located at a major source and is subject to the provisions
of this subpart is also subject to 40 CFR part 70 or part 71 operating
permit requirements.
Sec. 63.761 Definitions.
All terms used in this subpart shall have the meaning given them in
the Clean Air Act (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, pressure relief devices, sampling connection systems, open-ended
valves, or lines, valves, flanges, or other connectors.
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.
Black oil means hydrocarbon (petroleum) liquid with an initial
producing gas-to-oil ratio (GOR) less than 0.31 cubic meters per liter
and an API gravity less than 40 degrees.
Boiler means an enclosed device using controlled flame combustion
and having the primary purpose of recovering and exporting thermal
energy in the form of steam or hot water. Boiler also means any
industrial furnace as defined in 40 CFR 260.10.
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 one or more control devices. If gas or vapor from
regulated equipment is routed to a process (e.g., to a fuel gas
system), the conveyance system 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 organic HAP emissions.
Condensate means hydrocarbon liquid separated from natural gas that
condenses due to changes in the temperature, pressure, or both, and
[[Page 32630]]
remains liquid at standard conditions, as specified in Sec. 63.2.
Continuous recorder means a data recording device that either
records an instantaneous data value at least once every hour or records
hourly or more frequent block average values.
Control device means any equipment used for recovering or oxidizing
HAP or 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
(i.e., injected into the flame zone of a combustion device), 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 or closed-vent systems.
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. 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, but are not limited to, 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, or from storage vessels or automatic transfer facilities or
other such equipment, including product loading racks, to pipelines or
any other forms of transportation. For the purposes of this subpart,
the point at which such liquids or natural gas enters a natural gas
processing plant is a point of custody transfer.
Equipment leaks means emissions of HAP from ancillary equipment (as
defined in this section) and compressors.
Facility means any grouping of equipment where hydrocarbon liquids
are processed, upgraded (i.e., remove impurities or other constituents
to meet contract specifications), 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 and storage
source category. For the purpose of a major source determination,
facility (including a building, structure, or installation) means oil
and natural gas production and processing equipment that is located
within the boundaries of an individual surface site as defined in this
section. 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 or surface unit areas, surface fee tracts, surface lease
tracts, or separate surface sites, whether or not connected by a road,
waterway, power line or pipeline, 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, a compressor station
that transports natural gas to a natural gas processing plant, 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.
Fixed-roof means a cover that is mounted on a 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
combustion device occupied by the flame envelope.
Flash tank. See the definition for gas-condensate-glycol (GCG)
separator.
Flow indicator means a device which indicates whether gas flow is
present in a line or whether the valve position would allow gas flow to
be 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 of
gas produced per liter of crude oil or other hydrocarbon liquid.
Glycol dehydration unit means a device in which a liquid glycol
(including, but not limited to, ethylene glycol, diethylene glycol, or
triethylene glycol) absorbent directly contacts a natural gas stream
and absorbs water 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 in the glycol dehydration unit reboiler. The
``lean'' glycol is then recycled.
Glycol dehydration unit baseline operations means operations
representative of the glycol dehydration unit operations as of June 17,
1999. For the purposes of this subpart, for determining the percentage
of overall HAP emission reduction attributable to process
modifications, baseline operations shall be parameter values
(including, but not limited to, glycol circulation rate or glycol-HAP
absorbency) that represent actual long-term conditions (i.e., at least
1 year). Glycol dehydration units in operation for less than 1 year
shall document that the parameter values represent expected long-term
operating conditions had process modifications not been made.
Glycol dehydration unit process vent means either the glycol
dehydration unit reboiler vent and the vent from the GCG separator
(flash tank), if present.
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 or to a control device.
Hazardous air pollutants or HAP means the chemical compounds listed
in section 112(b) of the Clean Air 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 compliance.
Hydrocarbon liquid means any naturally occurring, unrefined
petroleum liquid.
In VHAP service means that a piece of ancillary equipment or
compressor either contains or contacts a fluid (liquid or gas) which
has a total volatile HAP (VHAP) concentration equal to or greater than
10 percent by weight as determined according to the provisions of
Sec. 63.772(a).
In wet gas service means that a piece of equipment contains or
contacts the field gas before the extraction of natural gas liquids.
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 is not
physically formed into one manufactured or assembled unit with the
combustion section; rather, the energy recovery section is 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 preheat the incoming vent stream or combustion air.
[[Page 32631]]
Initial producing GOR means the producing standard cubic meters of
gas per liter at the time that the reservoir pressure is above the
bubble point pressure (or dewpoint pressure for a gas).
Initial startup means the first time a new or reconstructed source
begins production. For the purposes of this subpart, initial startup
does not include subsequent startups (as defined in this section) of
equipment, for example, following malfunctions or shutdowns.
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
station 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 aggregated for a major source determination.
Natural gas means a naturally occurring mixture of hydrocarbon and
nonhydrocarbon gases found in geologic formations beneath the earth's
surface. The principal hydrocarbon constituent is methane.
Natural gas liquids (NGL) means the liquid hydrocarbons, such as
ethane, propane, butane, pentane, natural gasoline, and condensate that
are extracted from field natural gas.
Natural gas processing plant (gas plant) means any processing site
engaged in the extraction of natural gas liquids from field gas, or the
fractionation of mixed NGL to natural gas products, or a combination of
both.
No detectable emissions means no escape of HAP from a device or
system to the atmosphere as determined by:
(1) Instrument monitoring results in accordance with the
requirements of Sec. 63.772(c); and
(2) The absence of 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, indicates that an owner or operator has complied with
an applicable operating parameter limitation, over the appropriate
averaging period as specified in Sec. 63.772(f) or (g).
Operating permit means a permit required by 40 CFR part 70 or part
71.
Organic monitoring device means an instrument used to indicate the
concentration level of organic compounds exiting a control device based
on a detection principle such as infra-red, photoionization, or thermal
conductivity.
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 an enclosed device using a controlled flame,
the primary purpose of which is to transfer heat to a process fluid or
process material that is not a fluid, or to a heat transfer material
for use in a process (rather than for steam generation).
Produced water means water that is extracted from the earth from an
oil or natural gas production well, or 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.
Reciprocating compressor means a piece of equipment that increases
the pressure of a process gas by positive displacement, employing
linear movement of the drive shaft.
Relief device means a device used only to release an unplanned,
non-routine discharge in order to avoid safety hazards or equipment
damage. 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 meets both of the following
conditions: it 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 it 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.
Shutdown means for purposes including, but not limited to, periodic
maintenance, replacement of equipment, or repair, the cessation of
operation of a glycol dehydration unit, or other affected source under
this subpart, or equipment required or used solely to comply with this
subpart.
Startup means the setting into operation of a glycol dehydration
unit, or other affected equipment under this subpart, or equipment
required or used to comply with this subpart. Startup includes initial
startup and operation solely for the purpose of testing equipment.
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 liquid with a stock tank GOR
equal to or greater than 0.31 cubic meters per liter and an API gravity
equal to or greater than 40 degrees and an actual annual average
hydrocarbon liquid throughput equal to or greater than 79,500 liters
per day. Flash emissions occur when dissolved hydrocarbons in the fluid
evolve from solution when the fluid pressure is reduced.
Surface site means any combination of one or more graded pad sites,
gravel pad sites, foundations, platforms, or the 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 an instrument used to monitor
temperature and having a minimum accuracy of 2 percent of
the temperature being monitored expressed in deg.C, or 2.5
deg.C, whichever is greater. The temperature monitoring device may
[[Page 32632]]
measure temperature in degrees Fahrenheit or degrees Celsius, or both.
Total organic compounds or TOC, as used in this subpart, means
those compounds which can be measured according to the procedures of
Method 18, 40 CFR part 60, appendix A.
Volatile hazardous air pollutant concentration or VHAP
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 Startups, shutdowns, and malfunctions.
(a) The provisions set forth in this subpart shall apply at all
times except during startups or shutdowns, during malfunctions, and
during periods of non-operation of the affected sources (or specific
portion thereof) resulting in cessation of the emissions to which this
subpart applies. However, during the startup, shutdown, malfunction, or
period of non-operation of one portion of an affected source, all
emission points which can comply with the specific provisions to which
they are subject must do so during the startup, shutdown, malfunction,
or period of non-operation.
(b) The owner or operator shall not shut down items of equipment
that are required or utilized for compliance with the provisions of
this subpart during times when emissions are being routed to such items
of equipment, if the shutdown would contravene requirements of this
subpart applicable to such items of equipment. This paragraph does not
apply if the item of equipment is malfunctioning, or if the owner or
operator must shut down the equipment to avoid damage due to a
contemporaneous startup, shutdown, or malfunction of the affected
source or a portion thereof.
(c) During startups, shutdowns, and malfunctions when the
requirements of this subpart do not apply pursuant to paragraphs (a)
and (b) of this section, the owner or operator shall implement, to the
extent reasonably available, measures to prevent or minimize excess
emissions to the maximum extent practical. For purposes of this
paragraph, the term ``excess emissions'' means emissions in excess of
those that would have occurred if there were no startup, shutdown, or
malfunction, and the owner or operator complied with the relevant
provisions of this subpart. The measures to be taken shall be
identified in the applicable startup, shutdown, and malfunction plan,
and may include, but are not limited to, air pollution control
technologies, recovery technologies, work practices, pollution
prevention, monitoring, and/or changes in the manner of operation of
the source. Back-up control devices are not required, but may be used
if availabl
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