[Federal Register Volume 64, Number 116 (Thursday, June 17, 1999)]
[Rules and Regulations]
[Pages 32610-32664]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 99-12894]
[[Page 32609]]
_______________________________________________________________________
Part II
Environmental Protection Agency
_______________________________________________________________________
40 CFR Part 63
National Emission Standards for Hazardous Air Pollutants: Oil and
Natural Gas Production and Natural Gas Transmission and Storage; Final
Rule
Federal Register / Vol. 64, No. 116 / Thursday, June 17, 1999 / Rules
and Regulations
[[Page 32610]]
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 63
[AD-FRL-6346-8]
RIN 2060-AE34
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
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rules.
-----------------------------------------------------------------------
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
[[Page 32611]]
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
[[Page 32614]]
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............................................... <1 <1 <1
Nitrogen oxides............................................. <5 <1 <1
Carbon monoxide............................................. <1 <1 <1
Energy (Kilowatt hours per year)................................ 38,000 3,800 None
Implementation costs (Million of July 1993 $):
Total installed capital..................................... 6.5 0.7 0.28
Total annual................................................ 4.0 0.4 0.3
----------------------------------------------------------------------------------------------------------------
* No new major sources are anticipated for this source category after the effective date for new sources and in
the first 3 years following promulgation of the rule.
The EPA estimates that the final natural gas transmission and
storage standards for existing sources will result in a reduction of
HAP emissions from 2,100 Mg/yr to 1,710 Mg/yr. No new major sources are
anticipated in the first 3 years after promulgation of this NESHAP.
Table 1 also 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
existing natural gas transmission and storage facilities.
The air emission reductions achieved by these standards, when
combined with the air emission reductions achieved by other standards
mandated by the Act, will accomplish the primary goal of the Act to:
* * * enhance the quality of the Nation's air resources so as to
promote the public health and welfare and the productive capacity of
its population.
B. Secondary Environmental Impacts
Other environmental impacts are those associated with operation of
certain air emission control devices. The EPA's secondary air emissions
impact analyses for the oil and natural gas production source category
consider a facility's ability to handle collected vapors. Some remotely
located facilities may not be able to use collected vapor for fuel or
recycle it back into the process. In addition, it may not be
technically feasible for some facilities to safely utilize the non-
condensable vapor streams from condenser systems as an alternative fuel
source. An option for these facilities is to combust these vapors by
flaring, rather than installing condensers.
These limitations are reflected in the analyses conducted by the
EPA. In the analyses, the EPA estimated that (1) 45 percent of all
impacted production facilities will be able to use collected vapors
from installed control options as an alternative fuel source for an on-
site combustion device such as a process heater or the glycol
dehydration unit firebox, (2) 45 percent will be able to recycle
collected vapors from installed control options into a low pressure
header system for combination with other hydrocarbon streams handled at
the facility, and (3) 10 percent will direct all collected vapor to an
on-site flare. The secondary air impacts are associated with flare
operations.
[[Page 32617]]
The adverse secondary air impacts would be minimal in comparison to
the primary HAP reduction benefits from the implementation of the
control options for major oil and natural gas sources. The estimated
national annual increase in secondary air pollutant emissions that
would result from the use of a flare to comply with the standards is
estimated to be less than 1.0 Mg/yr for both sulfur oxide
(SOX) 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 available.
(d) The owner or operator shall prepare a startup, shutdown, or
malfunction plan as required in Sec. 63.6(e)(3) except that the plan is
not required to be incorporated by reference into the source's title V
permit as specified in Sec. 63.6(e)(3)(i). Instead, the owner or
operator shall keep the plan on record as required by
Sec. 63.6(e)(3)(v). The failure of the plan to adequately minimize
emissions during startup, shutdown, or malfunctions does not shield an
owner or operator from enforcement actions.
Sec. 63.763 [Reserved].
Sec. 63.764 General standards.
(a) Table 1 of this subpart specifies the provisions of subpart A
(General Provisions) that apply and those that do not apply to owners
and operators of affected sources subject to this subpart.
(b) All reports required under this subpart shall be sent to the
Administrator at the appropriate address listed in Sec. 63.13. Reports
may be submitted on electronic media.
(c) Except as specified in paragraph (e) of this section, the owner
or operator of an affected source located at an existing or new major
source of HAP emissions shall comply with the standards in this subpart
as specified in paragraphs (c)(1) through (3) of this section.
(1) For each glycol dehydration unit process vent subject to this
subpart, the owner or operator shall comply with the requirements
specified in paragraphs (c)(1)(i) through (iii) of this section.
(i) The owner or operator shall comply with the control
requirements for glycol dehydration unit process vents specified in
Sec. 63.765;
(ii) The owner or operator shall comply with the monitoring
requirements specified in Sec. 63.773; and
(iii) The owner or operator shall comply with the recordkeeping and
reporting requirements specified in Secs. 63.774 and 63.775.
(2) For each storage vessel with the potential for flash emissions
subject to this subpart, the owner or operator shall comply with the
requirements specified in paragraphs (c)(2)(i) through (iii) of this
section.
(i) The control requirements for storage vessels specified in
Sec. 63.766;
(ii) The monitoring requirements specified in Sec. 63.773; and
(iii) The recordkeeping and reporting requirements specified in
Secs. 63.774 and 63.775.
(3) For ancillary equipment (as defined in Sec. 63.761) and
compressors at a natural gas processing plant subject to this subpart,
the owner or operator shall comply with the requirements for equipment
leaks specified in Sec. 63.769.
(d) [Reserved]
(e) Exemptions. (1) The owner or operator is exempt from the
requirements of paragraph (c)(1) of this section if the criteria listed
in paragraph (e)(1)(i) or (e)(1)(ii) are met. Records of the
determination of these criteria must be maintained as required in
Sec. 63.774(d)(1) of this subpart.
(i) The actual annual average flowrate of natural gas to the glycol
dehydration unit is less than 85 thousand standard cubic meters per
day, as determined by the procedures specified in Sec. 63.772(b)(1) of
this subpart; or
(ii) The actual average emissions of benzene from the glycol
dehydration unit process vent to the atmosphere are less than 0.90
megagram per year, as determined by the procedures specified in
Sec. 63.772(b)(2) of this subpart.
(2) The owner or operator is exempt from the requirements of
paragraph (c)(3) of this section for ancillary equipment (as defined in
Sec. 63.761) and compressors at a natural gas processing plant subject
to this subpart, if the criteria listed in paragraphs (e)(2)(i) and
(e)(2)(ii) are met. Records of the determination of these criteria must
be maintained as required in Sec. 63.774(d)(2) of this subpart.
(i) Any ancillary equipment and compressors that contain or contact
a fluid (liquid or gas) must have a total VHAP concentration less than
10 percent by weight, as determined by the procedures specified in
Sec. 63.772(a) of this subpart; and
(ii) That ancillary equipment and compressors must operate in VHAP
service less than 300 hours per calendar year.
(f) Each owner or operator of a major HAP source subject to this
subpart is required to apply for a 40 CFR part 70 or part 71 operating
permit from the appropriate permitting authority. If the Administrator
has approved a State operating permit program under 40 CFR part 70, the
permit shall be obtained from the State authority. If a State operating
permit program has not been approved, the owner or operator of a source
shall apply to the EPA Regional Office pursuant to 40 CFR part 71.
(g) [Reserved]
(h) [Reserved]
(i) In all cases where the provisions of this subpart require an
owner or operator to repair leaks by a specified time after the leak is
detected, it is a violation of this standard to fail to take
[[Page 32633]]
action to repair the leak(s) within the specified time. If action is
taken to repair the leak(s) within the specified time, failure of that
action to successfully repair the leak(s) is not a violation of this
standard. However, if the repairs are unsuccessful, a leak is detected
and the owner or operator shall take further action as required by the
applicable provisions of this subpart.
Sec. 63.765 Glycol dehydration unit process vent standards.
(a) This section applies to each glycol dehydration unit subject to
this subpart with an actual annual average natural gas flowrate equal
to or greater than 85 thousand standard cubic meters per day and with
actual average benzene glycol dehydration unit process vent emissions
equal to or greater than 0.90 megagrams per year, that must be
controlled for HAP emissions as specified in Sec. 63.764(c)(1)(i).
(b) Except as provided in paragraph (c) of this section, an owner
or operator of a glycol dehydration unit process vent shall comply with
the requirements specified in paragraphs (b)(1) and (b)(2) of this
section.
(1) For each glycol dehydration unit process vent, the owner or
operator shall control air emissions by either paragraph (b)(1)(i) or
(b)(1)(ii) of this section.
(i) The owner or operator shall connect the process vent to a
control device or a combination of control devices through a closed-
vent system. The closed-vent system shall be designed and operated in
accordance with the requirements of Sec. 63.771(c). The control
device(s) shall be designed and operated in accordance with the
requirements of Sec. 63.771(d).
(ii) The owner or operator shall connect the process vent to a
control device or combination of control devices through a closed-vent
system and the outlet benzene emissions from the control device(s)
shall be reduced to a level less than 0.90 megagrams per year. The
closed-vent system shall be designed and operated in accordance with
the requirements of Sec. 63.771(c). The control device(s) shall be
designed and operated in accordance with the requirements of
Sec. 63.771(d), except that the performance levels specified in
Sec. 63.771(d)(1)(i) and (ii) do not apply.
(2) One or more safety devices that vent directly to the atmosphere
may be used on the air emission control equipment installed to comply
with paragraph (b)(1) of this section.
(c) As an alternative to the requirements of paragraph (b) of this
section, the owner or operator may comply with one of the requirements
specified in paragraphs (c)(1) through (3) of this section.
(1) The owner or operator shall control air emissions by connecting
the process vent to a process natural gas line.
(2) The owner or operator shall demonstrate, to the Administrator's
satisfaction, that the total HAP emissions to the atmosphere from the
glycol dehydration unit process vent are reduced by 95.0 percent
through process modifications, or a combination of process
modifications and one or more control devices, in accordance with the
requirements specified in Sec. 63.771(e).
(3) Control of HAP emissions from a GCG separator (flash tank) vent
is not required if the owner or operator demonstrates, to the
Administrator's satisfaction, that total emissions to the atmosphere
from the glycol dehydration unit process vent are reduced by one of the
levels specified in paragraphs (c)(3)(i) through (c)(3)(ii) of this
section, through the installation and operation of controls as
specified in paragraph (b)(1) of this section.
(i) HAP emissions are reduced by 95.0 percent or more.
(ii) Benzene emissions are reduced to a level less than 0.90
megagrams per year.
Sec. 63.766 Storage vessel standards.
(a) This section applies to each storage vessel with the potential
for flash emissions (as defined in Sec. 63.761) subject to this
subpart.
(b) The owner or operator of a storage vessel with the potential
for flash emissions (as defined in Sec. 63.761) shall comply with one
of the control requirements specified in paragraphs (b)(1) and (2) of
this section.
(1) The owner or operator shall equip the affected storage vessel
with the potential for flash emissions with a cover that is connected,
through a closed-vent system that meets the conditions specified in
Sec. 63.771(c), to a control device or a combination of control devices
that meets any of the conditions specified in Sec. 63.771(d). The cover
shall be designed and operated in accordance with the requirements of
Sec. 63.771(b).
(2) The owner or operator of a pressure storage vessel that is
designed to operate as a closed system shall operate the storage vessel
with no detectable emissions at all times that material is in the
storage vessel, except as provided for in paragraph (c) of this
section.
(c) One or more safety devices that vent directly to the atmosphere
may be used on the storage vessel and air emission control equipment
complying with paragraphs (b)(1) and (2) of this section.
(d) This section does not apply to storage vessels for which the
owner or operator is meeting the requirements specified in 40 CFR part
60, subpart Kb; or is meeting the requirements specified in 40 CFR part
63, subparts G or CC.
Sec. 63.767 [Reserved].
Sec. 63.768 [Reserved].
Sec. 63.769 Equipment leak standards.
(a) This section applies to equipment subject to this subpart,
located at natural gas processing plants and specified in paragraphs
(a)(1) and (a)(2) of this section, that contains or contacts a fluid
(liquid or gas) that has a total VHAP concentration equal to or greater
than 10 percent by weight (determined according to the procedures
specified in Sec. 63.772(a)) and that operates in VHAP service equal to
or greater than 300 hours per calendar year.
(1) Ancillary equipment, as defined in Sec. 63.761; and
(2) Compressors.
(b) This section does not apply to ancillary equipment and
compressors for which the owner or operator is meeting the requirements
specified in subpart H of this part; or is meeting the requirements
specified in 40 CFR part 60, subpart KKK.
(c) For each piece of ancillary equipment and each compressor
subject to this section located at an existing or new source, the owner
or operator shall meet the requirements specified in 40 CFR part 61,
subpart V, Secs. 61.241 through 61.247, except as specified in
paragraphs (c)(1) through (8) of this section.
(1) Each pressure relief device in gas/vapor service shall be
monitored quarterly and within 5 days after each pressure release to
detect leaks, except under the following conditions.
(i) The owner or operator has obtained permission from the
Administrator to use an alternative means of emission limitation that
achieves a reduction in emissions of VHAP at least equivalent to that
achieved by the control required in this subpart.
(ii) The pressure relief device is located in a nonfractionating
facility that is monitored only by non-facility personnel, it may be
monitored after a pressure release the next time the monitoring
personnel are on site, instead of within 5 days. Such a pressure relief
device shall not be allowed to operate for more than 30 days after a
pressure release without monitoring.
(2) For pressure relief devices, if an instrument reading of 10,000
parts per
[[Page 32634]]
million or greater is measured, a leak is detected.
(3) For pressure relief devices, when a leak is detected, it shall
be repaired as soon as practicable, but no later than 15 calendar days
after it is detected, unless a delay in repair of equipment is granted
under 40 CFR 61.242-10.
(4) Sampling connection systems are exempt from the requirements of
40 CFR 61.242-5.
(5) Pumps in VHAP service, valves in gas/vapor and light liquid
service, and pressure relief devices in gas/vapor service that are
located at a nonfractionating plant that does not have the design
capacity to process 283,000 standard cubic meters per day or more of
field gas are exempt from the routine monitoring requirements of 40 CFR
61.242-2(a)(1) and 61.242-7(a), and paragraphs (c)(1) through (3) of
this section.
(6) Pumps in VHAP service, valves in gas/vapor and light liquid
service, and pressure relief devices in gas/vapor service located
within a natural gas processing plant that is located on the Alaskan
North Slope are exempt from the routine monitoring requirements of 40
CFR 61.242-2(a)(1) and 61.242-7(a), and (c)(1) through (3) of this
section.
(7) Reciprocating compressors in wet gas service are exempt from
the compressor control requirements of 40 CFR 61.242-3.
(8) Flares used to comply with this subpart shall comply with the
requirements of Sec. 63.11(b).
Sec. 63.770 [Reserved].
Sec. 63.771 Control equipment requirements.
(a) This section applies to each cover, closed-vent system, and
control device installed and operated by the owner or operator to
control air emissions as required by the provisions of this subpart.
Compliance with paragraphs (b), (c), and (d) of this section will be
determined by review of the records required by Sec. 63.774 and the
reports required by Sec. 63.775, by review of performance test results,
and by inspections.
(b) Cover requirements. (1) The cover and all openings on the cover
(e.g., access hatches, sampling ports, and gauge wells) shall be
designed to form a continuous barrier over the entire surface area of
the liquid in the tank.
(2) Each cover opening shall be secured in a closed, sealed
position (e.g., covered by a gasketed lid or cap) whenever material is
in the unit on which the cover is installed except during those times
when it is necessary to use an opening as follows:
(i) To add material to, or remove material from the unit (this
includes openings necessary to equalize or balance the internal
pressure of the unit following changes in the level of the material in
the unit);
(ii) To inspect or sample the material in the unit;
(iii) To inspect, maintain, repair, or replace equipment located
inside the unit; or
(iv) To vent liquids, gases, or fumes from the unit through a
closed-vent system to a control device designed and operated in
accordance with the requirements of paragraphs (c) and (d) of this
section.
(c) Closed-vent system requirements. (1) The closed-vent system
shall route all gases, vapors, and fumes emitted from the material in a
HAP emissions unit to a control device that meets the requirements
specified in paragraph (d) of this section.
(2) The closed-vent system shall be designed and operated with no
detectable emissions.
(3) If the closed-vent system contains one or more bypass devices
that could be used to divert all or a portion of the gases, vapors, or
fumes from entering the control device, the owner or operator shall
meet the requirements specified in paragraphs (c)(3)(i) and (c)(3)(ii)
of this section.
(i) For each bypass device, except as provided for in paragraph
(c)(3)(ii) of this section, the owner or operator shall either:
(A) Properly install, calibrate, maintain, and operate a flow
indicator at the inlet to the bypass device that could divert the
stream away from the control device to the atmosphere that takes a
reading at least once every 15 minutes and sounds an alarm when the
bypass device is open such that the stream is being, or could be,
diverted away from the control device to the atmosphere; or
(B) Secure the bypass device valve installed at the inlet to the
bypass device in the non-diverting position using a car-seal or a lock-
and-key type configuration. The owner or operator shall visually
inspect the seal or closure mechanism at least once every month to
verify that the valve is maintained in the non-diverting position and
the vent stream is not diverted through the bypass device.
(ii) Low leg drains, high point bleeds, analyzer vents, open-ended
valves or lines, and safety devices are not subject to the requirements
of paragraph (c)(3)(i) of this section.
(d) Control device requirements. (1) The control device used to
reduce HAP emissions in accordance with the standards of this subpart
shall be one of the control devices specified in paragraphs (d)(1)(i)
through (iii) of this section.
(i) An enclosed combustion device (e.g., thermal vapor incinerator,
catalytic vapor incinerator, boiler, or process heater) that is
designed and operated in accordance with one of the following
performance requirements:
(A) Reduces the mass content of either TOC or total HAP in the
gases vented to the device by 95.0 percent by weight or greater as
determined in accordance with the requirements of Sec. 63.772(e); or
(B) Reduces the concentration of either TOC or total HAP in the
exhaust gases at the outlet to the device to a level equal to or less
than 20 parts per million by volume on a dry basis corrected to 3
percent oxygen as determined in accordance with the requirements of
Sec. 63.772(e); or
(C) Operates at a minimum residence time of 0.5 seconds at a
minimum temperature of 760 deg.C.
(D) If a boiler or process heater is used as the control device,
then the vent stream shall be introduced into the flame zone of the
boiler or process heater.
(ii) A vapor recovery device (e.g., carbon adsorption system or
condenser) or other control device that is designed and operated to
reduce the mass content of either TOC or total HAP in the gases vented
to the device by 95.0 percent by weight or greater as determined in
accordance with the requirements of Sec. 63.772(e).
(iii) A flare that is designed and operated in accordance with the
requirements of Sec. 63.11(b).
(2) [Reserved]
(3) The owner or operator shall demonstrate that a control device
achieves the performance requirements of paragraph (d)(1) of this
section as specified in Sec. 63.772(e).
(4) The owner or operator shall operate each control device in
accordance with the requirements specified in paragraphs (d)(4)(i) and
(ii) of this section.
(i) Each control device used to comply with this subpart shall be
operating at all times when gases, vapors, and fumes are vented from
the HAP emissions unit or units through the closed-vent system to the
control device, as required under Secs. 63.765, 63.766, and 63.769,
except when maintenance or repair on a unit cannot be completed without
a shutdown of the control device. An owner or operator may vent more
than one unit to a control device used to comply with this subpart.
(ii) For each control device monitored in accordance with the
requirements of Sec. 63.773(d), the owner or operator shall demonstrate
compliance according to
[[Page 32635]]
the requirements of Sec. 63.772(f) or (g), as applicable.
(5) For each carbon adsorption system used as a control device to
meet the requirements of paragraph (d)(1) of this section, the owner or
operator shall manage the carbon as follows:
(i) Following the initial startup of the control device, all carbon
in the control device shall be replaced with fresh carbon on a regular,
predetermined time interval that is no longer than the carbon service
life established for the carbon adsorption system.
(ii) The spent carbon removed from the carbon adsorption system
shall be either regenerated, reactivated, or burned in one of the units
specified in paragraphs (d)(5)(ii)(A) through (d)(5)(ii)(G) of this
section.
(A) Regenerated or reactivated in a thermal treatment unit for
which the owner or operator has been issued a final permit under 40 CFR
part 270 that implements the requirements of 40 CFR part 264, subpart
X.
(B) Regenerated or reactivated in a thermal treatment unit equipped
with and operating air emission controls in accordance with this
section.
(C) Regenerated or reactivated in a thermal treatment unit equipped
with and operating organic air emission controls in accordance with a
national emissions standard for HAP under another subpart in 40 CFR
part 61 or this part.
(D) Burned in a hazardous waste incinerator for which the owner or
operator has been issued a final permit under 40 CFR part 270 that
implements the requirements of 40 CFR part 264, subpart O.
(E) Burned in a hazardous waste incinerator which the owner or
operator has designed and operates in accordance with the requirements
of 40 CFR part 265, subpart O.
(F) Burned in a boiler or industrial furnace for which the owner or
operator has been issued a final permit under 40 CFR part 270 that
implements the requirements of 40 CFR part 266, subpart H.
(G) Burned in a boiler or industrial furnace which the owner or
operator has designed and operates in accordance with the interim
status requirements of 40 CFR part 266, subpart H.
(e) Process modification requirements. Each owner or operator that
chooses to comply with Sec. 63.765(c)(2) shall meet the requirements
specified in paragraphs (e)(1) through (e)(3) of this section.
(1) The owner or operator shall determine glycol dehydration unit
baseline operations (as defined in Sec. 63.761). Records of glycol
dehydration unit baseline operations shall be retained as required
under Sec. 63.774(b)(10).
(2) The owner or operator shall document, to the Administrator's
satisfaction, the conditions for which glycol dehydration unit baseline
operations shall be modified to achieve the 95.0 percent overall HAP
emission reduction, either through process modifications or through a
combination of process modifications and one or more control devices.
If a combination of process modifications and one or more control
devices are used, the owner or operator shall also establish the
percent HAP reduction to be achieved by the control device to achieve
an overall HAP emission reduction of 95.0 percent for the glycol
dehydration unit process vent. Only modifications in glycol dehydration
unit operations directly related to process changes, including, but not
limited to, changes in glycol circulation rate or glycol-HAP
absorbency, shall be allowed. Changes in the inlet gas characteristics
or natural gas throughput rate shall not be considered in determining
the overall HAP emission reduction.
(3) The owner or operator that achieves a 95.0 percent HAP emission
reduction using process modifications alone shall comply with paragraph
(e)(3)(i) of this section. The owner or operator that achieves a 95.0
percent HAP emission reduction using a combination of process
modifications and one or more control devices shall comply with
paragraphs (e)(3)(i) and (e)(3)(ii) of this section.
(i) The owner or operator shall maintain records, as required in
Sec. 63.774(b)(11), that the facility continues to operate in
accordance with the conditions specified under paragraph (e)(2) of this
section.
(ii) The owner or operator shall comply with the control device
requirements specified in paragraph (d) of this section, except that
the emission reduction achieved shall be the emission reduction
specified for the control device(s) in paragraph (e)(2) of this
section.
Sec. 63.772 Test methods, compliance procedures, and compliance
demonstrations.
(a) Determination of material VHAP or HAP concentration to
determine the applicability of the equipment leak standards under this
subpart (Sec. 63.769). Each piece of ancillary equipment and
compressors are presumed to be in VHAP service or in wet gas service
unless an owner or operator demonstrates that the piece of equipment is
not in VHAP service or in wet gas service.
(1) For a piece of ancillary equipment and compressors to be
considered not in VHAP service, it must be determined that the percent
VHAP content can be reasonably expected never to exceed 10.0 percent by
weight. For the purposes of determining the percent VHAP content of the
process fluid that is contained in or contacts a piece of ancillary
equipment or compressor, Method 18 of 40 CFR part 60, appendix A, shall
be used.
(2) For a piece of ancillary equipment and compressors to be
considered in wet gas service, it must be determined that it contains
or contacts the field gas before the extraction of natural gas liquids.
(b) Determination of glycol dehydration unit flowrate or benzene
emissions. The procedures of this paragraph shall be used by an owner
or operator to determine glycol dehydration unit natural gas flowrate
or benzene emissions to meet the criteria for an exemption from control
requirements under Sec. 63.764(e)(1).
(1) The determination of actual flowrate of natural gas to a glycol
dehydration unit shall be made using the procedures of either paragraph
(b)(1)(i) or (b)(1)(ii) of this section.
(i) The owner or operator shall install and operate a monitoring
instrument that directly measures natural gas flowrate to the glycol
dehydration unit with an accuracy of plus or minus 2 percent or better.
The owner or operator shall convert annual natural gas flowrate to a
daily average by dividing the annual flowrate by the number of days per
year the glycol dehydration unit processed natural gas.
(ii) The owner or operator shall document, to the Administrator's
satisfaction, that the actual annual average natural gas flowrate to
the glycol dehydration unit is less than 85 thousand standard cubic
meters per day.
(2) The determination of actual average benzene emissions from a
glycol dehydration unit shall be made using the procedures of either
paragraph (b)(2)(i) or (b)(2)(ii) of this section. Emissions shall be
determined either uncontrolled, or with federally enforceable controls
in place.
(i) The owner or operator shall determine actual average benzene
emissions using the model GRI-GLYCalcTM, Version 3.0 or
higher, and the procedures presented in the associated GRI-
GLYCalcTM Technical Reference Manual. Inputs to the model
shall be representative of actual operating conditions of the glycol
dehydration unit and may be
[[Page 32636]]
determined using the procedures documented in the Gas Research
Institute (GRI) report entitled ``Atmospheric Rich/Lean Method for
Determining Glycol Dehydrator Emissions'' (GRI-95/0368.1); or
(ii) The owner or operator shall determine an average mass rate of
benzene emissions in kilograms per hour through direct measurement by
performing three runs of Method 18, 40 CFR Part 60, appendix A (or an
equivalent method), and averaging the results of the three runs. Annual
emissions in kilograms per year shall be determined by multiplying the
mass rate by the number of hours the unit is operated per year. This
result shall be converted to megagrams per year.
(c) No detectable emissions test procedure. (1) The no detectable
emissions test procedure shall be conducted in accordance with Method
21, 40 CFR part 60, appendix A.
(2) The detection instrument shall meet the performance criteria of
Method 21, 40 CFR part 60, appendix A, except that the instrument
response factor criteria in section 3.1.2(a) of Method 21 shall be for
the average composition of the fluid and not for each individual
organic compound in the stream.
(3) The detection instrument shall be calibrated before use on each
day of its use by the procedures specified in Method 21, 40 CFR part
60, appendix A.
(4) Calibration gases shall be as follows:
(i) Zero air (less than 10 parts per million by volume hydrocarbon
in air); and
(ii) A mixture of methane in air at a concentration less than
10,000 parts per million by volume.
(5) An owner or operator may choose to adjust or not adjust the
detection instrument readings to account for the background organic
concentration level. If an owner or operator chooses to adjust the
instrument readings for the background level, the background level
value must be determined according to the procedures in Method 21 of 40
CFR part 60, appendix A.
(6)(i) Except as provided in paragraph (c)(6)(i) of this section,
the detection instrument shall meet the performance criteria of Method
21 of 40 CFR part 60, appendix A, except the instrument response factor
criteria in section 3.1.2(a) of Method 21 shall be for the average
composition of the process fluid not each individual volatile organic
compound in the stream. For process streams that contain nitrogen, air,
or other inerts which are not organic hazardous air pollutants or
volatile organic compounds, the average stream response factor shall be
calculated on an inert-free basis.
(ii) If no instrument is available at the facility that will meet
the performance criteria specified in paragraph (c)(6)(i) of this
section, the instrument readings may be adjusted by multiplying by the
average response factor of the process fluid, calculated on an inert-
free basis as described in paragraph (c)(6)(i) of this section.
(7) An owner or operator must determine if a potential leak
interface operates with no detectable emissions using the applicable
procedure specified in paragraph (c)(7)(i) or (c)(7)(ii) of this
section.
(i) If an owner or operator chooses not to adjust the detection
instrument readings for the background organic concentration level,
then the maximum organic concentration value measured by the detection
instrument is compared directly to the applicable value for the
potential leak interface as specified in paragraph (c)(8) of this
section.
(ii) If an owner or operator chooses to adjust the detection
instrument readings for the background organic concentration level, the
value of the arithmetic difference between the maximum organic
concentration value measured by the instrument and the background
organic concentration value as determined in paragraph (c)(5) of this
section is compared with the applicable value for the potential leak
interface as specified in paragraph (c)(8) of this section.
(8) A potential leak interface is determined to operate with no
detectable organic emissions if the organic concentration value
determined in paragraph (c)(7) of this section, is less than 500 parts
per million by volume.
(d) [Reserved]
(e) Control device performance test procedures. This paragraph
applies to the performance testing of control devices. The owners or
operators shall demonstrate that a control device achieves the
performance requirements of Sec. 63.771(d)(1) or (e)(3)(ii) using
either a performance test as specified in paragraph (e)(3) of this
section or a design analysis as specified in paragraph (e)(4) of this
section. The owner or operator may elect to use the alternative
procedures in paragraph (e)(5) of this section for performance testing
of a condenser used to control emissions from a glycol dehydration unit
process vent.
(1) The following control devices are exempt from the requirements
to conduct performance tests and design analyses under this section:
(i) A flare that is designed and operated in accordance with
Sec. 63.11(b);
(ii) A boiler or process heater with a design heat input capacity
of 44 megawatts or greater;
(iii) A boiler or process heater into which the vent stream is
introduced with the primary fuel or is used as the primary fuel;
(iv) A boiler or process heater burning hazardous waste for which
the owner or operator has either been issued a final permit under 40
CFR part 270 and complies with the requirements of 40 CFR part 266,
subpart H; or has certified compliance with the interim status
requirements of 40 CFR part 266, subpart H;
(v) A hazardous waste incinerator for which the owner or operator
has been issued a final permit under 40 CFR part 270 and complies with
the requirements of 40 CFR part 264, subpart O; or has certified
compliance with the interim status requirements of 40 CFR part 265,
subpart O.
(vi) A control device for which a performance test was conducted
for determining compliance with a regulation promulgated by the EPA and
the test was conducted using the same methods specified in this section
and either no process changes have been made since the test, or the
owner or operator can demonstrate that the results of the performance
test, with or without adjustments, reliably demonstrate compliance
despite process changes.
(2) An owner or operator shall design and operate each flare in
accordance with the requirements specified in Sec. 63.11(b) and in
paragraphs (e)(2)(i) and (e)(2)(ii) of this section.
(i) The compliance determination shall be conducted using Method 22
of 40 CFR part 60, appendix A, to determine visible emissions.
(ii) An owner or operator is not required to conduct a performance
test to determine percent emission reduction or outlet organic HAP or
TOC concentration when a flare is used.
(3) For a performance test conducted to demonstrate that a control
device meets the requirements of Sec. 63.771(d)(1) or (e)(3)(ii), the
owner or operator shall use the test methods and procedures specified
in paragraphs (e)(3)(i) through (e)(3)(iv) of this section. The
performance test shall be conducted according to the schedule specified
in Sec. 63.7(a)(2) and the results of the performance test shall be
submitted in the Notification of Compliance Status Report as required
in Sec. 63.775(d)(1)(ii.
(i) Method 1 or 1A, 40 CFR part 60, appendix A, as appropriate,
shall be used for selection of the sampling sites in paragraphs
(e)(3)(i)(A) and (B) of this section. Any references to particulate
[[Page 32637]]
mentioned in Methods 1 and 1A do not apply to this section.
(A) To determine compliance with the control device percent
reduction requirement specified in Sec. 63.771(d)(1)(i)(A), (d)(1)(ii)
or (e)(3)(ii), sampling sites shall be located at the inlet of the
first control device, and at the outlet of the final control device.
(B) To determine compliance with the enclosed combustion device
total HAP concentration limit specified in Sec. 63.771(d)(1)(i)(B), the
sampling site shall be located at the outlet of the combustion device.
(ii) The gas volumetric flowrate shall be determined using Method
2, 2A, 2C, or 2D, 40 CFR part 60, appendix A, as appropriate.
(iii) To determine compliance with the control device percent
reduction performance requirement in
Sec. 63.771(d)(1)(i)(A),(d)(1)(ii), and (e)(3)(ii), the owner or
operator shall use either Method 18, 40 CFR part 60, appendix A or
Method 25A, 40 CFR part 60, appendix A; alternatively, any other method
or data that have been validated according to the applicable procedures
in Method 301, 40 CFR part 63, appendix A, may be used. The following
procedures shall be used to calculate percent reduction efficiency:
(A) The minimum sampling time for each run shall be 1 hour in which
either an integrated sample or a minimum of four grab samples shall be
taken. If grab sampling is used, then the samples shall be taken at
approximately equal intervals in time, such as 15-minute intervals
during the run.
(B) The mass rate of either TOC (minus methane and ethane) or total
HAP (Ei, Eo) shall be computed.
(1) The following equations shall be used:
[GRAPHIC] [TIFF OMITTED] TR17JN99.000
[GRAPHIC] [TIFF OMITTED] TR17JN99.001
Where:
Cij, Coj = Concentration of sample component j of
the gas stream at the inlet and outlet of the control device,
respectively, dry basis, parts per million by volume.
Ei, Eo = Mass rate of TOC (minus methane and
ethane) or total HAP at the inlet and outlet of the control device,
respectively, dry basis, kilogram per hour.
Mij, Moj = Molecular weight of sample component j
of the gas stream at the inlet and outlet of the control device,
respectively, gram/gram-mole.
Qi, Qo = Flowrate of gas stream at the inlet and
outlet of the control device, respectively, dry standard cubic meter
per minute.
K2 = Constant, 2.494x10-6 (parts per million)
(gram-mole per standard cubic meter) (kilogram/gram) (minute/hour),
where standard temperature (gram-mole per standard cubic meter) is
20 deg.C.
(2) When the TOC mass rate is calculated, all organic compounds
(minus methane and ethane) measured by Method 18, 40 CFR part 60,
appendix A, or Method 25A, 40 CFR part 60, appendix A, shall be summed
using the equations in paragraph (e)(3)(iii)(B)(1) of this section.
(3) When the total HAP mass rate is calculated, only HAP chemicals
listed in Table 1 of this subpart shall be summed using the equations
in paragraph (e)(3)(iii)(B)(1) of this section.
(C) The percent reduction in TOC (minus methane and ethane) or
total HAP shall be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR17JN99.002
Where:
Rcd = Control efficiency of control device, percent.
Ei = Mass rate of TOC (minus methane and ethane) or total
HAP at the inlet to the control device as calculated under paragraph
(e)(3)(iii)(B) of this section, kilograms TOC per hour or kilograms HAP
per hour.
Eo = Mass rate of TOC (minus methane and ethane) or total
HAP at the outlet of the control device, as calculated under paragraph
(e)(3)(iii)(B) of this section, kilograms TOC per hour or kilograms HAP
per hour.
(D) If the vent stream entering a boiler or process heater with a
design capacity less than 44 megawatts is introduced with the
combustion air or as a secondary fuel, the weight-percent reduction of
total HAP or TOC (minus methane and ethane) across the device shall be
determined by comparing the TOC (minus methane and ethane) or total HAP
in all combusted vent streams and primary and secondary fuels with the
TOC (minus methane and ethane) or total HAP exiting the device,
respectively.
(iv) To determine compliance with the enclosed combustion device
total HAP concentration limit specified in Sec. 63.771(d)(1)(i)(B), the
owner or operator shall use either Method 18, 40 CFR part 60, appendix
A, or Method 25A, 40 CFR part 60, appendix A, to measure either TOC
(minus methane and ethane) or total HAP. Alternatively, any other
method or data that have been validated according to Method 301 of
appendix A of this part, may be used. The following procedures shall be
used to calculate parts per million by volume concentration, corrected
to 3 percent oxygen:
(A) The minimum sampling time for each run shall be 1 hour, in
which either an integrated sample or a minimum of four grab samples
shall be taken. If grab sampling is used, then the samples shall be
taken at approximately equal intervals in time, such as 15-minute
intervals during the run.
(B) The TOC concentration or total HAP concentration shall be
calculated according to paragraph (e)(3)(iv)(B)(1) or (e)(3)(iv)(B)(2)
of this section.
(1) The TOC concentration is the sum of the concentrations of the
individual components and shall be computed for each run using the
following equation:
[GRAPHIC] [TIFF OMITTED] TR17JN99.003
Where:
CTOC = Concentration of total organic compounds minus
methane and ethane, dry basis, parts per million by volume.
Cji = Concentration of sample component j of sample i, dry
basis, parts per million by volume.
n = Number of components in the sample.
x = Number of samples in the sample run.
(2) The total HAP concentration shall be computed according to the
equation in paragraph (e)(3)(iv)(B)(1) of this section, except that
only HAP chemicals listed in Table 1 of this subpart shall be summed.
(C) The TOC concentration or total HAP concentration shall be
corrected to 3 percent oxygen as follows:
(1) The emission rate correction factor for excess air, integrated
sampling and analysis procedures of Method 3B, 40 CFR part 60, appendix
A, shall be used to determine the oxygen concentration. The samples
shall be taken during the same time that the samples are taken for
determining TOC concentration or total HAP concentration.
(2) The TOC or HAP concentration shall be corrected for percent
oxygen by using the following equation:
[GRAPHIC] [TIFF OMITTED] TR17JN99.004
[[Page 32638]]
Where:
Cc = TOC concentration or total HAP concentration corrected
to 3 percent oxygen, dry basis, parts per million by volume.
Cm = TOC concentration or total HAP concentration, dry
basis, parts per million by volume.
%O2d = Concentration of oxygen, dry basis, percent by
volume.
(4) For a design analysis conducted to meet the requirements of
Sec. 63.771(d)(1) or (e)(3)(ii), the owner or operator shall meet the
requirements specified in paragraphs (e)(4)(i) and (e)(4)(ii) of this
section. Documentation of the design analysis shall be submitted as a
part of the Notification of Compliance Status Report as required in
Sec. 63.775(d)(1)(i).
(i) The design analysis shall include analysis of the vent stream
characteristics and control device operating parameters for the
applicable control device as specified in paragraphs (e)(4)(i)(A)
through (F) of this section.
(A) For a thermal vapor incinerator, the design analysis shall
include the vent stream composition, constituent concentrations, and
flowrate and shall establish the design minimum and average
temperatures in the combustion zone and the combustion zone residence
time.
(B) For a catalytic vapor incinerator, the design analysis shall
include the vent stream composition, constituent concentrations, and
flowrate and shall establish the design minimum and average
temperatures across the catalyst bed inlet and outlet, and the design
service life of the catalyst.
(C) For a boiler or process heater, the design analysis shall
include the vent stream composition, constituent concentrations, and
flowrate; shall establish the design minimum and average flame zone
temperatures and combustion zone residence time; and shall describe the
method and location where the vent stream is introduced into the flame
zone.
(D) For a condenser, the design analysis shall include the vent
stream composition, constituent concentrations, flowrate, relative
humidity, and temperature, and shall establish the design outlet
organic compound concentration level, design average temperature of the
condenser exhaust vent stream, and the design average temperatures of
the coolant fluid at the condenser inlet and outlet. As an alternative
to the design analysis, an owner or operator may elect to use the
procedures specified in paragraph (e)(5) of this section.
(E) For a regenerable carbon adsorption system, the design analysis
shall include the vent stream composition, constituent concentrations,
flowrate, relative humidity, and temperature, and shall establish the
design exhaust vent stream organic compound concentration level,
adsorption cycle time, number and capacity of carbon beds, type and
working capacity of activated carbon used for the carbon beds, design
total regeneration stream flow over the period of each complete carbon
bed regeneration cycle, design carbon bed temperature after
regeneration, design carbon bed regeneration time, and design service
life of the carbon.
(F) For a nonregenerable carbon adsorption system, such as a carbon
canister, the design analysis shall include the vent stream
composition, constituent concentrations, flowrate, relative humidity,
and temperature, and shall establish the design exhaust vent stream
organic compound concentration level, capacity of the carbon bed, type
and working capacity of activated carbon used for the carbon bed, and
design carbon replacement interval based on the total carbon working
capacity of the control device and source operating schedule. In
addition, these systems will incorporate dual carbon canisters in case
of emission breakthrough occurring in one canister.
(ii) If the owner or operator and the Administrator do not agree on
a demonstration of control device performance using a design analysis
then the disagreement shall be resolved using the results of a
performance test performed by the owner or operator in accordance with
the requirements of paragraph (e)(3) of this section. The Administrator
may choose to have an authorized representative observe the performance
test.
(5) As an alternative to the procedures in paragraphs (e)(3) and
(e)(4)(i)(D) of this section, an owner or operator may elect to use the
procedures documented in the GRI report entitled, ``Atmospheric Rich/
Lean Method for Determining Glycol Dehydrator Emissions'' (GRI-95/
0368.1) as inputs for the model GRI-GLYCalcTM, Version 3.0
or higher, to determine condenser performance.
(f) Compliance demonstration for control device performance
requirements. This paragraph applies to the demonstration of compliance
with the control device performance requirements specified in
Secs. 63.771(d)(1)(ii) and 63.765(c)(2). Compliance shall be
demonstrated using the requirements in paragraphs (f)(1) through (f)(3)
of this section. As an alternative, an owner or operator that installs
a condenser as the control device to achieve the requirements specified
in Sec. 63.771(d)(1)(ii) or Sec. 63.765(c)(2), may demonstrate
compliance according to paragraph (g) of this section. An owner or
operator may switch between compliance with paragraph (f) of this
section and compliance with paragraph (g) of this section only after at
least 1 year of operation in compliance with the selected approach.
Notification of such a change in the compliance method shall be
reported in the next Periodic Report, as required in Sec. 63.775(e),
following the change.
(1) The owner or operator shall establish a site specific maximum
or minimum monitoring parameter value (as appropriate) according to the
requirements of Sec. 63.773(d)(5)(i).
(2) The owner or operator shall calculate the daily average of the
applicable monitored parameter in accordance with Sec. 63.773(d)(4).
(3) Compliance with the operating parameter limit is achieved when
the daily average of the monitoring parameter value calculated under
paragraph (f)(2) of this section is either equal to or greater than the
minimum or equal to or less than the maximum monitoring value
established under paragraph (f)(1) of this section.
(g) Compliance demonstration with percent reduction performance
requirements--condensers. This paragraph applies to the demonstration
of compliance with the performance requirements specified in
Sec. 63.771(d)(1)(ii) or Sec. 63.765(c)(2) for condensers. Compliance
shall be demonstrated using the procedures in paragraphs (g)(1) through
(g)(3) of this section.
(1) The owner or operator shall establish a site-specific condenser
performance curve according to Sec. 63.773(d)(5)(ii).
(2) Compliance with the percent reduction requirement in
Sec. 63.771(d)(1)(ii) or Sec. 63.765(c)(2) shall be demonstrated by the
procedures in paragraphs (g)(2)(i) through (g)(2)(iii) of this section.
(i) The owner or operator must calculate the daily average
condenser outlet temperature in accordance with Sec. 63.773(d)(4).
(ii) The owner or operator shall determine the condenser efficiency
for the current operating day using the daily average condenser outlet
temperature calculated under paragraph (g)(2)(i) of this section and
the condenser performance curve established under paragraph (g)(1) of
this section.
(iii) Except as provided in paragraphs (g)(2)(iii) (A) and (B) of
this section, at the end of each operating day, the
[[Page 32639]]
owner or operator shall calculate the 365-day average HAP emission
reduction from the condenser efficiencies determined in paragraph
(g)(2)(ii) of this section for the preceding 365 operating days. If the
owner or operator uses a combination of process modifications and a
condenser in accordance with the requirements of Sec. 63.765(c)(2), the
365-day average HAP emission reduction shall be calculated using the
emission reduction achieved through process modifications and the
condenser efficiency determined in paragraph (g)(2)(ii) of this
section, both for the previous 365 operating days.
(A) After the compliance dates specified in Sec. 63.760(f), an
owner or operator with less than 120 days of data for determining
average HAP emission reduction, shall calculate the average HAP
emission reduction for the first 120 days of operation after the
compliance dates. Compliance with the performance requirements is
achieved if the 120-day average HAP emission reduction is equal to or
greater than 90.0 percent.
(B) After 120 days and no more than 364 days of operation after the
compliance dates specified in Sec. 63.760(f), the owner or operator
shall calculate the average HAP emission reduction as the HAP emission
reduction averaged over the number of days between the current day and
the applicable compliance date. Compliance with the performance
requirements is achieved if the average HAP emission reduction is equal
to or greater than 90.0 percent.
(3) If the owner or operator has data for 365 days or more of
operation, compliance is achieved with the emission limitation
specified in Sec. 63.771(d)(1)(ii) or Sec. 63.765(c)(2) if the average
HAP emission reduction calculated in paragraph (g)(2)(iii) of this
section is equal to or greater than 95.0 percent.
Sec. 63.773 Inspection and monitoring requirements.
(a) This section applies to an owner or operator using air emission
controls in accordance with the requirements of Secs. 63.765 and
63.766.
(b) [Reserved]
(c) Cover and closed-vent system inspection and monitoring
requirements. (1) For each closed-vent system or cover required to
comply with this section, the owner or operator shall comply with the
requirements of paragraphs (c) (2) through (7) of this section.
(2) Except as provided in paragraphs (c) (5) and (6) of this
section, each closed-vent system shall be inspected according to the
procedures and schedule specified in paragraphs (c)(2) (i) and (ii) of
this section, and each cover shall be inspected according to the
procedures and schedule specified in paragraph (c)(2)(iii) of this
section.
(i) For each closed-vent system joints, seams, or other connections
that are permanently or semi-permanently sealed (e.g., a welded joint
between two sections of hard piping or a bolted and gasketed ducting
flange), the owner or operator shall:
(A) Conduct an initial inspection according to the procedures
specified in Sec. 63.772(c) to demonstrate that the closed-vent system
operates with no detectable emissions.
(B) Conduct annual visual inspections for defects that could result
in air emissions. Defects include, but are not limited to, visible
cracks, holes, or gaps in piping; loose connections; or broken or
missing caps or other closure devices. The owner or operator shall
monitor a component or connection using the procedures in
Sec. 63.772(c) to demonstrate that it operates with no detectable
emissions following any time the component is repaired or replaced or
the connection is unsealed.
(ii) For closed-vent system components other than those specified
in paragraph (c)(2)(i) of this section, the owner or operator shall:
(A) Conduct an initial inspection according to the procedures
specified in Sec. 63.772(c) to demonstrate that the closed-vent system
operates with no detectable emissions.
(B) Conduct annual inspections according to the procedures
specified in Sec. 63.772(c) to demonstrate that the components or
connections operate with no detectable emissions.
(C) Conduct annual visual inspections for defects that could result
in air emissions. Defects include, but are not limited to, visible
cracks, holes, or gaps in ductwork; loose connections; or broken or
missing caps or other closure devices.
(iii) For each cover, the owner or operator shall:
(A) Conduct visual inspections for defects that could result in air
emissions. Defects include, but are not limited to, visible cracks,
holes, or gaps in the cover, or between the cover and the separator
wall; broken, cracked, or otherwise damaged seals or gaskets on closure
devices; and broken or missing hatches, access covers, caps, or other
closure devices. In the case where the tank is buried partially or
entirely underground, inspection is required only for those portions of
the cover that extend to or above the ground surface, and those
connections that are on such portions of the cover (e.g., fill ports,
access hatches, gauge wells, etc.) and can be opened to the atmosphere.
(B) The inspections shall be conducted initially, following the
installation of the cover. Thereafter, the owner or operator shall
perform the inspection at least once every calendar year, except as
provided in paragraphs (c) (5) and (6) of this section.
(3) In the event that a leak or defect is detected, the owner or
operator shall repair the leak or defect as soon as practicable, except
as provided in paragraph (c)(4) of this section.
(i) A first attempt at repair shall be made no later than 5
calendar days after the leak is detected.
(ii) Repair shall be completed no later than 15 calendar days after
the leak is detected.
(4) Delay of repair of a closed-vent system or cover for which
leaks or defects have been detected is allowed if the repair is
technically infeasible without a shutdown, as defined in Sec. 63.761,
or if the owner or operator determines that emissions resulting from
immediate repair would be greater than the fugitive emissions likely to
result from delay of repair. Repair of such equipment shall be complete
by the end of the next shutdown.
(5) Any parts of the closed-vent system or cover that are
designated, as described in paragraphs (c)(5) (i) and (ii) of this
section, as unsafe to inspect are exempt from the inspection
requirements of paragraphs (c)(2)(i), (ii), and (iii) of this section
if:
(i) The owner or operator determines that the equipment is unsafe
to inspect because inspecting personnel would be exposed to an imminent
or potential danger as a consequence of complying with paragraphs
(c)(2)(i), (ii), or (iii) of this section; and
(ii) The owner or operator has a written plan that requires
inspection of the equipment as frequently as practicable during safe-
to-inspect times.
(6) Any parts of the closed-vent system or cover that are
designated, as described in paragraphs (c)(6) (i) and (ii) of this
section, as difficult to inspect are exempt from the inspection
requirements of paragraphs (c)(2)(i), (ii), and (iii) of this section
if:
(i) The owner or operator determines that the equipment cannot be
inspected without elevating the inspecting personnel more than 2 meters
above a support surface; and
(ii) The owner or operator has a written plan that requires
inspection of the equipment at least once every 5 years.
(7) Records shall be maintained as specified in Sec. 63.774(b)(5)
through (8).
[[Page 32640]]
(d) Control device monitoring requirements. (1) For each control
device, except as provided for in paragraph (d)(2) of this section, the
owner or operator shall install and operate a continuous parameter
monitoring system in accordance with the requirements of paragraphs
(d)(3) through (9) of this section. The continuous monitoring system
shall be designed and operated so that a determination can be made on
whether the control device is achieving the applicable performance
requirements of Sec. 63.771(d) or Sec. 63.771(e)(3). The continuous
parameter monitoring system shall meet the following specifications and
requirements:
(i) Each continuous parameter monitoring system shall measure data
values at least once every hour and record either:
(A) Each measured data value; or
(B) Each block average value for each 1-hour period or shorter
periods calculated from all measured data values during each period. If
values are measured more frequently than once per minute, a single
value for each minute may be used to calculate the hourly (or shorter
period) block average instead of all measured values.
(ii) The monitoring system must be installed, calibrated, operated,
and maintained in accordance with the manufacturer's specifications or
other written procedures that provide reasonable assurance that the
monitoring equipment is operating properly.
(2) An owner or operator is exempt from the monitoring requirements
specified in paragraphs (d)(3) through (9) of this section for the
following types of control devices:
(i) A boiler or process heater in which all vent streams are
introduced with the primary fuel or is used as the primary fuel; or
(ii) A boiler or process heater with a design heat input capacity
equal to or greater than 44 megawatts.
(3) The owner or operator shall install, calibrate, operate, and
maintain a device equipped with a continuous recorder to measure the
values of operating parameters appropriate for the control device as
specified in either paragraph (d)(3)(i), (d)(3)(ii), or (d)(3)(iii) of
this section.
(i) A continuous monitoring system that measures the following
operating parameters as applicable:
(A) For a thermal vapor incinerator, a temperature monitoring
device equipped with a continuous recorder. The monitoring device shall
have a minimum accuracy of 2 percent of the temperature
being monitored in deg.C ,or 2.5 deg.C, whichever value
is greater. The temperature sensor shall be installed at a location in
the combustion chamber downstream of the combustion zone.
(B) For a catalytic vapor incinerator, a temperature monitoring
device equipped with a continuous recorder. The device shall be capable
of monitoring temperature at two locations and have a minimum accuracy
of 2 percent of the temperature being monitored in deg.C,
or 2.5 deg.C, whichever value is greater. One temperature
sensor shall be installed in the vent stream at the nearest feasible
point to the catalyst bed inlet and a second temperature sensor shall
be installed in the vent stream at the nearest feasible point to the
catalyst bed outlet.
(C) For a flare, a heat sensing monitoring device equipped with a
continuous recorder that indicates the continuous ignition of the pilot
flame.
(D) For a boiler or process heater with a design heat input
capacity of less than 44 megawatts, a temperature monitoring device
equipped with a continuous recorder. The temperature monitoring device
shall have a minimum accuracy of 2 percent of the
temperature being monitored in deg.C, or 2.5 deg.C,
whichever value is greater. The temperature sensor shall be installed
at a location in the combustion chamber downstream of the combustion
zone.
(E) For a condenser, a temperature monitoring device equipped with
a continuous recorder. The temperature monitoring device shall have a
minimum accuracy of 2 percent of the temperature being
monitored in deg.C, or 2.5 deg.C, whichever value is
greater. The temperature sensor shall be installed at a location in the
exhaust vent stream from the condenser.
(F) For a regenerative-type carbon adsorption system:
(1) A continuous parameter monitoring system to measure and record
the average total regeneration stream mass flow or volumetric flow
during each carbon bed regeneration cycle. The integrating regenerating
stream flow monitoring device must have an accuracy of 10
percent; and
(2) A continuous parameter monitoring system to measure and record
the average carbon bed temperature for the duration of the carbon bed
steaming cycle and to measure the actual carbon bed temperature after
regeneration and within 15 minutes of completing the cooling cycle. The
temperature monitoring device shall have a minimum accuracy of
2 percent of the temperature being monitored in deg.C, or
2.5 deg.C, whichever value is greater.
(G) For a nonregenerative-type carbon adsorption system, the owner
or operator shall monitor the design carbon replacement interval
established using a performance test performed in accordance with
Sec. 63.772(e)(3) or a design analysis in accordance with
Sec. 63.772(e)(4)(i)(F) and shall be based on the total carbon working
capacity of the control device and source operating schedule.
(ii) A continuous monitoring system that measures the concentration
level of organic compounds in the exhaust vent stream from the control
device using an organic monitoring device equipped with a continuous
recorder. The monitor must meet the requirements of Performance
Specification 8 or 9 of appendix B of 40 CFR part 60 and must be
installed, calibrated, and maintained according to the manufacturer's
specifications.
(iii) A continuous monitoring system that measures alternative
operating parameters other than those specified in paragraph (d)(3)(i)
or (d)(3)(ii) of this section upon approval of the Administrator as
specified in Sec. 63.8(f)(1) through (5).
(4) Using the data recorded by the monitoring system, the owner or
operator must calculate the daily average value for each monitored
operating parameter for each operating day. If the HAP emissions unit
operation is continuous, the operating day is a 24-hour period. If HAP
emissions unit operation is not continuous, the operating day is the
total number of hours of control device operation per 24-hour period.
Valid data points must be available for 75 percent of the operating
hours in an operating day to compute the daily average.
(5) For each operating parameter monitor installed in accordance
with the requirements of paragraph (d)(3) of this section, the owner or
operator shall comply with paragraph (d)(5)(i) of this section for all
control devices except for condensers, and when condensers are
installed, the owner or operator shall also comply with paragraph
(d)(5)(ii) of this section.
(i) The owner or operator shall establish a minimum operating
parameter value or a maximum operating parameter value, as appropriate
for the control device, to define the conditions at which the control
device must be operated to continuously achieve the applicable
performance requirements of Sec. 63.771(d)(1) or Sec. 63.771(e)(3)(ii).
Each minimum or maximum operating parameter value shall be established
as follows:
[[Page 32641]]
(A) If the owner or operator conducts performance tests in
accordance with the requirements of Sec. 63.772(e)(3) to demonstrate
that the control device achieves the applicable performance
requirements specified in Sec. 63.771(d)(1) or Sec. 63.771(e)(3)(ii),
then the minimum operating parameter value or the maximum operating
parameter value shall be established based on values measured during
the performance test and supplemented, as necessary, by control device
design analysis or control device manufacturer recommendations or a
combination of both.
(B) If the owner or operator uses a control device design analysis
in accordance with the requirements of Sec. 63.772(e)(4) to demonstrate
that the control device achieves the applicable performance
requirements specified in Sec. 63.771(d)(1) or (e)(3)(ii), then the
minimum operating parameter value or the maximum operating parameter
value shall be established based on the control device design analysis
and may be supplemented by the control device manufacturer's
recommendations.
(ii) The owner or operator shall establish a condenser performance
curve showing the relationship between condenser outlet temperature and
condenser control efficiency. The curve shall be established as
follows:
(A) If the owner or operator conducts a performance test in
accordance with the requirements of Sec. 63.772(e)(3) to demonstrate
that the condenser achieves the applicable performance requirements in
Sec. 63.771(d)(1) or (e)(3)(ii), then the condenser performance curve
shall be based on values measured during the performance test and
supplemented as necessary by control device design analysis, or control
device manufacturer's recommendations, or a combination or both.
(B) If the owner or operator uses a control device design analysis
in accordance with the requirements of Sec. 63.772(e)(4)(i)(D) to
demonstrate that the condenser achieves the applicable performance
requirements specified in Sec. 63.771(d)(1) or (e)(3)(ii), then the
condenser performance curve shall be based on the condenser design
analysis and may be supplemented by the control device manufacturer's
recommendations.
(C) As an alternative to paragraphs (d)(5)(ii)(A) and (B) of this
section, the owner or operator may elect to use the procedures
documented in the GRI report entitled, ``Atmospheric Rich/Lean Method
for Determining Glycol Dehydrator Emissions'' (GRI-95/0368.1) as inputs
for the model GRI-GLYCalcTM, Version 3.0 or higher, to
generate a condenser performance curve.
(6) An excursion for a given control device is determined to have
occurred when the monitoring data or lack of monitoring data result in
any one of the criteria specified in paragraphs (d)(6)(i) through
(d)(6)(v) of this section being met. When multiple operating parameters
are monitored for the same control device and during the same operating
day and more than one of these operating parameters meets an excursion
criterion specified in paragraphs (d)(6)(i) through (d)(6)(v) of this
section, then a single excursion is determined to have occurred for the
control device for that operating day.
(i) An excursion occurs when the daily average value of a monitored
operating parameter is less than the minimum operating parameter limit
(or, if applicable, greater than the maximum operating parameter limit)
established for the operating parameter in accordance with the
requirements of paragraph (d)(5)(i) of this section.
(ii) An excursion occurs when the 365-day average condenser
efficiency calculated according to the requirements specified in
Sec. 63.772(g)(2)(iii) is less than 95.0 percent.
(iii) If an owner or operator has less than 365 days of data, an
excursion occurs when the average condenser efficiency calculated
according to the procedures specified in Sec. 63.772(g)(2)(iii)(A) or
(B) is less than 90.0 percent.
(iv) An excursion occurs when the monitoring data are not available
for at least 75 percent of the operating hours.
(v) If the closed-vent system contains one or more bypass devices
that could be used to divert all or a portion of the gases, vapors, or
fumes from entering the control device, an excursion occurs when:
(A) For each bypass line subject to Sec. 63.771(c)(3)(i)(A) the
flow indicator indicates that flow has been detected and that the
stream has been diverted away from the control device to the
atmosphere.
(B) For each bypass line subject to Sec. 63.771(c)(3)(i)(B), if the
seal or closure mechanism has been broken, the bypass line valve
position has changed, the key for the lock-and-key type lock has been
checked out, or the car-seal has broken.
(7) For each excursion, except as provided for in paragraph (d)(8)
of this section, the owner or operator shall be deemed to have failed
to have applied control in a manner that achieves the required
operating parameter limits. Failure to achieve the required operating
parameter limits is a violation of this standard.
(8) An excursion is not a violation of the operating parameter
limit as specified in paragraphs (d)(8)(i) and (d)(8)(ii) of this
section.
(i) An excursion does not count toward the number of excused
excursions allowed under paragraph (d)(8)(ii) of this section when the
excursion occurs during any one of the following periods:
(A) During a period of startup, shutdown, or malfunction when the
affected facility is operated during such period in accordance with the
facility's startup, shutdown, and malfunction plan; or
(B) During periods of non-operation of the unit or the process that
is vented to the control device (resulting in cessation of HAP
emissions to which the monitoring applies).
(ii) For each control device, or combinations of control devices
installed on the same HAP emissions unit, one excused excursion is
allowed per semiannual period for any reason. The initial semiannual
period is the 6-month reporting period addressed by the first Periodic
Report submitted by the owner or operator in accordance with
Sec. 63.775(e) of this subpart.
(9) Nothing in paragraphs (d)(1) through (d)(8) of this section
shall be construed to allow or excuse a monitoring parameter excursion
caused by any activity that violates other applicable provisions of
this subpart.
Sec. 63.774 Recordkeeping requirements.
(a) The recordkeeping provisions of 40 CFR part 63, subpart A, that
apply and those that do not apply to owners and operators of sources
subject to this subpart are listed in Table 2 of this subpart.
(b) Except as specified in paragraphs (c) and (d) of this section,
each owner or operator of a facility subject to this subpart shall
maintain the records specified in paragraphs (b)(1) through (b)(11) of
this section:
(1) The owner or operator of an affected source subject to the
provisions of this subpart shall maintain files of all information
(including all reports and notifications) required by this subpart. The
files shall be retained for at least 5 years following the date of each
occurrence, measurement, maintenance, corrective action, report or
period.
(i) All applicable records shall be maintained in such a manner
that they can be readily accessed.
(ii) The most recent 12 months of records shall be retained on site
or shall be accessible from a central location by
[[Page 32642]]
computer or other means that provides access within 2 hours after a
request.
(iii) The remaining 4 years of records may be retained offsite.
(iv) Records may be maintained in hard copy or computer-readable
form including, but not limited to, on paper, microfilm, computer,
floppy disk, magnetic tape, or microfiche.
(2) Records specified in Sec. 63.10(b)(2);
(3) Records specified in Sec. 63.10(c) for each monitoring system
operated by the owner or operator in accordance with the requirements
of Sec. 63.773(d). Notwithstanding the requirements of Sec. 63.10(c),
monitoring data recorded during periods identified in paragraphs
(b)(3)(i) through (b)(3)(iv) of this section shall not be included in
any average or percent leak rate computed under this subpart. Records
shall be kept of the times and durations of all such periods and any
other periods during process or control device operation when monitors
are not operating.
(i) Monitoring system breakdowns, repairs, calibration checks, and
zero (low-level) and high-level adjustments;
(ii) Startups, shutdowns, or malfunctions events. During startups,
shutdowns, or malfunction events, the owner or operator shall maintain
records indicating whether or not the startup, shutdown or malfunction
plan required under Sec. 63.762(d), was followed.
(iii) Periods of non-operation resulting in cessation of the
emissions to which the monitoring applies; and
(iv) Excursions due to invalid data as defined in
Sec. 63.773(d)(6)(iv).
(4) Each owner or operator using a control device to comply with
Sec. 63.764 of this subpart shall keep the following records up-to-date
and readily accessible:
(i) Continuous records of the equipment operating parameters
specified to be monitored under Sec. 63.773(d) of this subpart or
specified by the Administrator in accordance with
Sec. 63.773(d)(3)(iii) of this subpart. For flares, the hourly records
and records of pilot flame outages specified in Sec. 63.773(d)(3)(i)(C)
of this subpart shall be maintained in place of continuous records.
(ii) Records of the daily average value of each continuously
monitored parameter for each operating day determined according to the
procedures specified in Sec. 63.773(d)(4) of this subpart, except as
specified in paragraphs (b)(4)(ii)(A) and (B) of this section.
(A) For flares, records of the times and duration of all periods
during which all pilot flames are absent shall be kept rather than
daily averages.
(B) For condensers installed to comply with Sec. 63.765, records of
the annual 365-day rolling average condenser efficiency determined
under Sec. 63.772(g) shall be kept in addition to the daily averages.
(iii) Hourly records of whether the flow indicator specified under
Sec. 63.771(c)(3)(i)(A) was operating and whether flow was detected at
any time during the hour, as well as records of the times and durations
of all periods when the vent stream is diverted from the control device
or the monitor is not operating.
(iv) Where a seal or closure mechanism is used to comply with
Sec. 63.771(c)(3)(i)(B), hourly records of flow are not required. In
such cases, the owner or operator shall record that the monthly visual
inspection of the seals or closure mechanism has been done, and shall
record the duration of all periods when the seal mechanism is broken,
the bypass line valve position has changed, or the key for a lock-and-
key type lock has been checked out, and records of any car-seal that
has broken.
(5) Records identifying all parts of the cover or closed-vent
system that are designated as unsafe to inspect in accordance with
Sec. 63.773(c)(5), an explanation of why the equipment is unsafe to
inspect, and the plan for inspecting the equipment.
(6) Records identifying all parts of the cover or closed-vent
system that are designated as difficult to inspect in accordance with
Sec. 63.773(c)(6), an explanation of why the equipment is difficult to
inspect, and the plan for inspecting the equipment.
(7) For each inspection conducted in accordance with
Sec. 63.773(c), during which a leak or defect is detected, a record of
the information specified in paragraphs (b)(7)(i) through (b)(7)(viii)
of this section.
(i) The instrument identification numbers, operator name or
initials, and identification of the equipment.
(ii) The date the leak or defect was detected and the date of the
first attempt to repair the leak or defect.
(iii) Maximum instrument reading measured by the method specified
in Sec. 63.772(c) after the leak or defect is successfully repaired or
determined to be nonrepairable.
(iv) ``Repair delayed'' and the reason for the delay if a leak or
defect is not repaired within 15 calendar days after discovery of the
leak or defect.
(v) The name, initials, or other form of identification of the
owner or operator (or designee) whose decision it was that repair could
not be effected without a shutdown.
(vi) The expected date of successful repair of the leak or defect
if a leak or defect is not repaired within 15 calendar days.
(vii) Dates of shutdowns that occur while the equipment is
unrepaired.
(viii) The date of successful repair of the leak or defect.
(8) For each inspection conducted in accordance with Sec. 63.773(c)
during which no leaks or defects are detected, a record that the
inspection was performed, the date of the inspection, and a statement
that no leaks were detected.
(9) Records identifying ancillary equipment and compressors that
are subject to and controlled under the provisions of 40 CFR part 60,
subpart KKK; 40 CFR part 61, subpart V; or 40 CFR part 63, subpart H.
(10) Records of glycol dehydration unit baseline operations
calculated as required under Sec. 63.771(e)(1).
(11) Records required in Sec. 63.771(e)(3)(i) documenting that the
facility continues to operate under the conditions specified in
Sec. 63.771(e)(2).
(c) An owner or operator that elects to comply with the benzene
emission limit specified in Sec. 63.765(b)(1)(ii) shall document, to
the Administrator's satisfaction, the following items:
(1) The method used for achieving compliance and the basis for
using this compliance method; and
(2) The method used for demonstrating compliance with 0.90
megagrams per year of benzene.
(3) Any information necessary to demonstrate compliance as required
in the methods specified in paragraphs (c)(1) and (c)(2) of this
section.
(d) (1) An owner or operator that is exempt from control
requirements under Sec. 63.764(e)(1) shall maintain the records
specified in paragraph (d)(1)(i) or (d)(1)(ii) of this section, as
appropriate, for each glycol dehydration unit that is not controlled
according to the requirements of Sec. 63.764(c)(1)(i).
(i) The actual annual average natural gas throughput (in terms of
natural gas flowrate to the glycol dehydration unit per day) as
determined in accordance with Sec. 63.772(b)(1), or
(ii) The actual average benzene emissions (in terms of benzene
emissions per year) as determined in accordance with Sec. 63.772(b)(2).
(2) An owner or operator that is exempt from the control
requirements under Sec. 63.764(e)(2) of this subpart shall maintain the
following records:
(i) Information and data used to demonstrate that a piece of
equipment is not in VHAP service or not in wet gas service shall be
recorded in a log that is kept in a readily accessible location.
[[Page 32643]]
(ii) Identification and location of equipment, located at a natural
gas processing plant subject to this subpart, that is in VHAP service
less than 300 hours per year.
(e) Record the following when using a flare to comply with
Sec. 63.771(d):
(1) Flare design (i.e., steam-assisted, air-assisted, or non-
assisted);
(2) All visible emission readings, heat content determinations,
flowrate measurements, and exit velocity determinations made during the
compliance determination required by Sec. 63.772(e)(2); and
(3) All periods during the compliance determination when the pilot
flame is absent.
Sec. 63.775 Reporting requirements.
(a) The reporting provisions of subpart A of this part, that apply
and those that do not apply to owners and operators of sources subject
to this subpart are listed in Table 2 of this subpart.
(b) Each owner or operator of a major source subject to this
subpart shall submit the information listed in paragraphs (b)(1)
through (b)(6) of this section, except as provided in paragraphs (b)(7)
and (b)(8) of this section.
(1) The initial notifications required for existing affected
sources under Sec. 63.9(b)(2) shall be submitted by 1 year after an
affected source becomes subject to the provisions of this subpart or by
June 17, 2000, whichever is later. Affected sources that are major
sources on or before June 17, 2000 and plan to be area sources by June
17, 2002 shall include in this notification a brief, nonbinding
description of a schedule for the action(s) that are planned to achieve
area source status.
(2) The date of the performance evaluation as specified in
Sec. 63.8(e)(2), required only if the owner or operator is required by
the Administrator to conduct a performance evaluation for a continuous
monitoring system. A separate notification of the performance
evaluation is not required if it is included in the initial
notification submitted in accordance with paragraph (b)(1) of this
section.
(3) The planned date of a performance test at least 60 days before
the test in accordance with Sec. 63.7(b). Unless requested by the
Administrator, a site-specific test plan is not required by this
subpart. If requested by the Administrator, the owner or operator must
also submit the site-specific test plan required by Sec. 63.7(c) with
the notification of the performance test. A separate notification of
the performance test is not required if it is included in the initial
notification submitted in accordance with paragraph (b)(1) of this
section.
(4) A Notification of Compliance Status report as described in
paragraph (d) of this section;
(5) Periodic Reports as described in paragraph (e) of this section;
and
(6) Startup, shutdown, and malfunction reports specified in
Sec. 63.10(d)(5) shall be submitted as required. Separate startup,
shutdown, and malfunction reports as described in Sec. 63.10(d)(5) are
not required if the information is included in the Periodic Report
specified in paragraph (e) of this section.
(7) Each owner or operator of a glycol dehydration unit subject to
this subpart that is exempt from the control requirements for glycol
dehydration unit process vents in Sec. 63.765, is exempt from all
reporting requirements for major sources in this subpart, for that
unit.
(8) Each owner or operator of ancillary equipment and compressors
subject to this subpart that are exempt from the control requirements
for equipment leaks in Sec. 63.769, are exempt from all reporting
requirements for major sources in this subpart, for that equipment.
(c) [Reserved]
(d) Each owner or operator of a source subject to this subpart
shall submit a Notification of Compliance Status Report as required
under Sec. 63.9(h) within 180 days after the compliance date specified
in Sec. 63.760(f). In addition to the information required under
Sec. 63.9(h), the Notification of Compliance Status Report shall
include the information specified in paragraphs (d)(1) through (d)(11)
of this section. This information may be submitted in an operating
permit application, in an amendment to an operating permit application,
in a separate submittal, or in any combination of the three. If all of
the information required under this paragraph has been submitted at any
time prior to 180 days after the applicable compliance dates specified
in Sec. 63.760(f), a separate Notification of Compliance Status Report
is not required. If an owner or operator submits the information
specified in paragraphs (d)(1) through (d)(11) of this section at
different times, and/or different submittals, later submittals may
refer to earlier submittals instead of duplicating and resubmitting the
previously submitted information.
(1) If a closed-vent system and a control device other than a flare
are used to comply with Sec. 63.764, the owner or operator shall
submit:
(i) The design analysis documentation specified in
Sec. 63.772(e)(4) of this subpart, if the owner or operator elects to
prepare a design analysis; or
(ii) If the owner or operator elects to conduct a performance test,
the performance test results including the information specified in
paragraphs (d)(1)(ii)(A) and (B) of this section. Results of a
performance test conducted prior to the compliance date of this subpart
can be used provided that the test was conducted using the methods
specified in Sec. 63.772(e)(3) and that the test conditions are
representative of current operating conditions.
(A) The percent reduction of HAP or TOC, or the outlet
concentration of HAP or TOC (parts per million by volume on a dry
basis), determined as specified in Sec. 63.772(e)(3) of this subpart;
and
(B) The value of the monitored parameters specified in
Sec. 63.773(d) of this subpart, or a site-specific parameter approved
by the permitting agency, averaged over the full period of the
performance test.
(2) If a closed-vent system and a flare are used to comply with
Sec. 63.764, the owner or operator shall submit performance test
results including the information in paragraphs (d)(2) (i) and (ii) of
this section.
(i) All visible emission readings, heat content determinations,
flowrate measurements, and exit velocity determinations made during the
compliance determination required by Sec. 63.772(e)(2) of this subpart,
and
(ii) A statement of whether a flame was present at the pilot light
over the full period of the compliance determination.
(3) For each owner or operator subject to the provisions specified
in Sec. 63.769, the owner or operator shall submit the information
required by Sec. 61.247(a), except that the initial report required in
Sec. 61.247(a) shall be submitted as a part of the Notification of
Compliance Status Report required in paragraph (d) of this section. The
owner or operator shall also submit the information specified in
paragraphs (d)(3) (i) and (ii) of this section.
(i) The number of each equipment (e.g., valves, pumps, etc.)
excluding equipment in vacuum service, and
(ii) Any change in the information submitted in this paragraph
shall be provided to the Administrator as a part of subsequent Periodic
Reports described in paragraph (e)(2)(iv) of this section.
(4) The owner or operator shall submit one complete test report for
each test method used for a particular source.
(i) For additional tests performed using the same test method, the
results
[[Page 32644]]
specified in paragraph (d)(1)(ii) of this section shall be submitted,
but a complete test report is not required.
(ii) A complete test report shall include a sampling site
description, description of sampling and analysis procedures and any
modifications to standard procedures, quality assurance procedures,
record of operating conditions during the test, record of preparation
of standards, record of calibrations, raw data sheets for field
sampling, raw data sheets for field and laboratory analyses,
documentation of calculations, and any other information required by
the test method.
(5) For each control device other than a flare used to meet the
requirements of Sec. 63.764, the owner or operator shall submit the
information specified in paragraphs (d)(5) (i) through (iii) of this
section for each operating parameter required to be monitored in
accordance with the requirements of Sec. 63.773(d).
(i) The minimum operating parameter value or maximum operating
parameter value, as appropriate for the control device, established by
the owner or operator to define the conditions at which the control
device must be operated to continuously achieve the applicable
performance requirements of Sec. 63.771(d)(1) or (e)(3)(ii).
(ii) An explanation of the rationale for why the owner or operator
selected each of the operating parameter values established in
Sec. 63.773(d)(5). This explanation shall include any data and
calculations used to develop the value and a description of why the
chosen value indicates that the control device is operating in
accordance with the applicable requirements of Sec. 63.771(d)(1) or
Sec. 63.771(e)(3)(ii).
(iii) A definition of the source's operating day for purposes of
determining daily average values of monitored parameters. The
definition shall specify the times at which an operating day begins and
ends.
(6) Results of any continuous monitoring system performance
evaluations shall be included in the Notification of Compliance Status
Report.
(7) After a title V permit has been issued to the owner or operator
of an affected source, the owner or operator of such source shall
comply with all requirements for compliance status reports contained in
the source's title V permit, including reports required under this
subpart. After a title V permit has been issued to the owner or
operator of an affected source, and each time a notification of
compliance status is required under this subpart, the owner or operator
of such source shall submit the notification of compliance status to
the appropriate permitting authority following completion of the
relevant compliance demonstration activity specified in this subpart.
(8) The owner or operator that elects to comply with the
requirements of Sec. 63.765(b)(1)(ii) shall submit the records required
under Sec. 63.774(c).
(9) The owner or operator shall submit an analysis demonstrating
whether an affected source is a major source using the maximum
throughput calculated according to Sec. 63.760(a)(1).
(10) The owner or operator shall submit a statement as to whether
the source has complied with the requirements of this subpart.
(11) The owner or operator shall submit the analysis prepared under
Sec. 63.771(e)(2) to demonstrate the conditions by which the facility
will be operated to achieve an overall HAP emission reduction of 95.0
percent through process modifications or a combination of process
modifications and one or more control devices.
(e) Periodic Reports. An owner or operator shall prepare Periodic
Reports in accordance with paragraphs (e) (1) and (2) of this section
and submit them to the Administrator.
(1) An owner or operator shall submit Periodic Reports
semiannually, beginning 60 operating days after the end of the
applicable reporting period. The first report shall be submitted no
later than 240 days after the date the Notification of Compliance
Status Report is due and shall cover the 6-month period beginning on
the date the Notification of Compliance Status Report is due.
(2) The owner or operator shall include the information specified
in paragraphs (e)(2)(i) through (ix) of this section, as applicable.
(i) The information required under Sec. 63.10(e)(3). For the
purposes of this subpart and the information required under
Sec. 63.10(e)(3), excursions (as defined in Sec. 63.773(d)(6)) shall be
considered excess emissions.
(ii) A description of all excursions as defined in
Sec. 63.773(d)(6) of this subpart that have occurred during the 6-month
reporting period.
(A) For each excursion caused when the daily average value of a
monitored operating parameter is less than the minimum operating
parameter limit (or, if applicable, greater than the maximum operating
parameter limit), as specified in Sec. 63.773(d)(6)(i), the report must
include the daily average values of the monitored parameter, the
applicable operating parameter limit, and the date and duration of the
period that the excursion occurred.
(B) For each excursion caused when the 365-day average condenser
control efficiency is less than 95.0 percent, as specified in
Sec. 63.773(d)(6)(ii), the report must include the 365-day average
values of the condenser control efficiency, and the date and duration
of the period that the excursion occurred.
(C) For each excursion caused when condenser control efficiency is
less than 90.0 percent, as calculated according to the procedures
specified in Sec. 63.772(g)(2)(iii) (A) or (B), the report must include
the average values of the condenser control efficiency, and the date
and duration of the period that the excursion occurred.
(D) For each excursion caused by lack of monitoring data, as
specified in Sec. 63.773(d)(6)(iii), the report must include the date
and duration of the period when the monitoring data were not collected
and the reason why the data were not collected.
(iii) For each inspection conducted in accordance with
Sec. 63.773(c) during which a leak or defect is detected, the records
specified in Sec. 63.774(b)(7) must be included in the next Periodic
Report.
(iv) For each owner or operator subject to the provisions specified
in Sec. 63.769, the owner or operator shall comply with the reporting
requirements specified in 40 CFR 61.247, except that the Periodic
Reports shall be submitted on the schedule specified in paragraph
(e)(1) of this section.
(v) For each closed-vent system with a bypass line subject to
Sec. 63.771(c)(3)(i)(A), records required under Sec. 63.774(b)(4)(iii)
of all periods when the vent stream is diverted from the control device
through a bypass line. For each closed-vent system with a bypass line
subject to Sec. 63.771(c)(3)(i)(B), records required under
Sec. 63.774(b)(4)(iv) of all periods in which the seal mechanism is
broken, the bypass valve position has changed, or the key to unlock the
bypass line valve was checked out.
(vi) If an owner or operator elects to comply with
Sec. 63.765(b)(1)(ii), the records required under Sec. 63.774(c)(3).
(vii) The information in paragraphs (e)(2)(vii) (A) and (B) of this
section shall be stated in the Periodic Report, when applicable.
(A) No excursions.
(B) No continuous monitoring system has been inoperative, out of
control, repaired, or adjusted.
(viii) Any change in compliance methods as specified in
Sec. 63.772(f).
(ix) If the owner or operator elects to comply with
Sec. 63.765(c)(2), the records required under Sec. 63.774(b)(11).
(f) Notification of process change. Whenever a process change is
made, or
[[Page 32645]]
a change in any of the information submitted in the Notification of
Compliance Status Report, the owner or operator shall submit a report
within 180 days after the process change is made or as a part of the
next Periodic Report as required under paragraph (e) of this section,
whichever is sooner. The report shall include:
(1) A brief description of the process change;
(2) A description of any modification to standard procedures or
quality assurance procedures;
(3) Revisions to any of the information reported in the original
Notification of Compliance Status Report under paragraph (d) of this
section; and
(4) Information required by the Notification of Compliance Status
Report under paragraph (d) of this section for changes involving the
addition of processes or equipment.
Sec. 63.776 Delegation of authority.
(a) In delegating implementation and enforcement authority to a
State under section 112(l) of the Act, the authorities contained in
paragraph (b) of this section shall be retained by the Administrator
and not transferred to a State.
(b) Authorities will not be delegated to States for Secs. 63.772
and 63.777 of this subpart.
Sec. 63.777 Alternative means of emission limitation.
(a) If, in the judgment of the Administrator, an alternative means
of emission limitation will achieve a reduction in HAP emissions at
least equivalent to the reduction in HAP emissions from that source
achieved under the applicable requirements in Secs. 63.764 through
63.771, the Administrator will publish in the Federal Register a notice
permitting the use of the alternative means for purposes of compliance
with that requirement. The notice may condition the permission on
requirements related to the operation and maintenance of the
alternative means.
(b) Any notice under paragraph (a) of this section shall be
published only after public notice and an opportunity for a hearing.
(c) Any person seeking permission to use an alternative means of
compliance under this section shall collect, verify, and submit to the
Administrator information demonstrating that the alternative achieves
equivalent emission reductions.
Sec. 63.778 [Reserved]
Sec. 63.779 [Reserved]
Appendix to Subpart HH--Tables
Table 1 to Subpart HH.--List of Hazardous Air Pollutants for Subpart HH
------------------------------------------------------------------------
CAS Number a Chemical name
------------------------------------------------------------------------
75070.................................. Acetaldehyde
71432.................................. Benzene (includes benzene in
gasoline)
75150.................................. Carbon disulfide
463581................................. Carbonyl sulfide
100414................................. Ethyl benzene
107211................................. Ethylene glycol
50000.................................. Formaldehyde
110543................................. n-Hexane
91203.................................. Naphthalene
108883................................. Toluene
540841................................. 2,2,4-Trimethylpentane
1330207................................ Xylenes (isomers and mixture)
95476.................................. o-Xylene
108383................................. m-Xylene
106423................................. p-Xylene
------------------------------------------------------------------------
a CAS numbers refer to the Chemical Abstracts Services registry number
assigned to specific compounds, isomers, or mixtures of compounds.
Table 2 To Subpart HH.--Applicability of 40 CFR Part 63 General Provisions To Subpart HH
----------------------------------------------------------------------------------------------------------------
General provisions reference Applicable to subpart HH Explanation
----------------------------------------------------------------------------------------------------------------
Sec. 63.1(a)(1)................... Yes
Sec. 63.1(a)(2)................... Yes
Sec. 63.1(a)(3)................... Yes
Sec. 63.1(a)(4)................... Yes
Sec. 63.1(a)(5)................... No......................... Section reserved.
Sec. 63.1(a)(6) through (a)(8).... Yes
Sec. 63.1(a)(9)................... No......................... Section reserved.
Sec. 63.1(a)(10).................. Yes
Sec. 63.1(a)(11).................. Yes
Sec. 63.1(a)(12) through (a)(14).. Yes
Sec. 63.1(b)(1)................... No......................... Subpart HH specifies applicability.
Sec. 63.1(b)(2)................... Yes
Sec. 63.1(b)(3)................... No
Sec. 63.1(c)(1)................... No......................... Subpart HH specifies applicability.
Sec. 63.1(c)(2)................... No
Sec. 63.1(c)(3)................... No......................... Section reserved.
Sec. 63.1(c)(4)................... Yes
Sec. 63.1(c)(5)................... Yes
Sec. 63.1(d)...................... No......................... Section reserved.
Sec. 63.1(e)...................... Yes
Sec. 63.2......................... Yes........................ Except definition of major source is unique
for this source category and there are
additional definitions in subpart HH.
Sec. 63.3(a) through (c).......... Yes
Sec. 63.4(a)(1) through (a)(3).... Yes
Sec. 63.4(a)(4)................... No......................... Section reserved.
Sec. 63.4(a)(5)................... Yes
Sec. 63.4(b)...................... Yes
Sec. 63.4(c)...................... Yes
Sec. 63.5(a)(1)................... Yes
Sec. 63.5(a)(2)................... No......................... Preconstruction review required only for major
sources that commence construction after
promulgation of the standard.
Sec. 63.5(b)(1)................... Yes
Sec. 63.5(b)(2)................... No......................... Section reserved.
Sec. 63.5(b)(3)................... Yes
[[Page 32646]]
Sec. 63.5(b)(4)................... Yes
Sec. 63.5(b)(5)................... Yes
Sec. 63.5(b)(6)................... Yes
Sec. 63.5(c)...................... No......................... Section reserved.
Sec. 63.5(d)(1)................... Yes
Sec. 63.5(d)(2)................... Yes
Sec. 63.5(d)(3)................... Yes
Sec. 63.5(d)(4)................... Yes
Sec. 63.5(e)...................... Yes
Sec. 63.5(f)(1)................... Yes
Sec. 63.5(f)(2)................... Yes
Sec. 63.6(a)...................... Yes
Sec. 63.6(b)(1)................... Yes
Sec. 63.6(b)(2)................... Yes
Sec. 63.6(b)(3)................... Yes
Sec. 63.6(b)(4)................... Yes
Sec. 63.6(b)(5)................... Yes
Sec. 63.6(b)(6)................... No......................... Section reserved.
Sec. 63.6(b)(7)................... Yes
Sec. 63.6(c)(1)................... Yes
Sec. 63.6(c)(2)................... Yes
Sec. 63.6(c)(3) through (c)(4).... No......................... Section reserved.
Sec. 63.6(c)(5)................... Yes
Sec. 63.6(d)...................... No......................... Section reserved.
Sec. 63.6(e)...................... Yes........................ Except as otherwise specified.
Sec. 63.6(e)(1)(i)................ No......................... Addressed in Sec. 63.762.
Sec. 63.6(e)(1)(ii)............... Yes
Sec. 63.6(e)(1)(iii).............. Yes
Sec. 63.6(e)(2)................... Yes
Sec. 63.6(e)(3)(i)................ Yes........................ Except as otherwise specified.
Sec. 63.6(e)(3)(i)(A)............. No......................... Addressed by Sec. 63.762(c).
Sec. 63.6(e)(3)(i)(B)............. Yes
Sec. 63.6(e)(3)(i)(C)............. Yes
Sec. 63.6(e)(3)(ii) through Yes
(3)(vi).
Sec. 63.6(e)(3)(vii)..............
Sec. 63.6(e)(3)(vii)(A)........... Yes
Sec. 63.6(e)(3)(vii)(B)........... Yes........................ Except that the plan must provide for
operation in compliance with Sec. 63.762(c).
Sec. 63.6(e)(3)(vii)(C)........... Yes
Sec. 63.6(e)3)(viii).............. Yes
Sec. 63.6(f)(1)................... Yes
Sec. 63.6(f)(2)................... Yes
Sec. 63.6(f)(3)................... Yes
Sec. 63.6(g)...................... Yes
Sec. 63.6(h)...................... No......................... Subpart HH does not require continuous
emissions monitoring systems.
Sec. 63.6(i)(1) through (i)(14)... Yes
Sec. 63.6(i)(15).................. No......................... Section reserved.
Sec. 63.6(i)(16).................. Yes
Sec. 63.6(j)...................... Yes
Sec. 63.7(a)(1)................... Yes
Sec. 63.7(a)(2)................... Yes
Sec. 63.7(a)(3)................... Yes
Sec. 63.7(b)...................... Yes
Sec. 63.7(c)...................... Yes
Sec. 63.7(d)...................... Yes
Sec. 63.7(e)(1)................... Yes
Sec. 63.7(e)(2)................... Yes
Sec. 63.7(e)(3)................... Yes
Sec. 63.7(e)(4)................... Yes
Sec. 63.7(f)...................... Yes
Sec. 63.7(g)...................... Yes
Sec. 63.7(h)...................... Yes
Sec. 63.8(a)(1)................... Yes
Sec. 63.8(a)(2)................... Yes
Sec. 63.8(a)(3)................... No......................... Section reserved.
Sec. 63.8(a)(4)................... Yes
Sec. 63.8(b)(1)................... Yes
Sec. 63.8(b)(2)................... Yes
Sec. 63.8(b)(3)................... Yes
Sec. 63.8(c)(1)................... Yes
Sec. 63.8(c)(2)................... Yes
Sec. 63.8(c)(3)................... Yes
[[Page 32647]]
Sec. 63.8(c)(4)................... No
Sec. 63.8(c)(5) through (c)(8).... Yes
Sec. 63.8(d)...................... Yes
Sec. 63.8(e)...................... Yes........................ Subpart HH does not specifically require
continuous emissions monitor performance
evaluations, however, the Administrator can
request that one be conducted.
Sec. 63.8(f)(1) through (f)(5).... Yes
Sec. 63.8(f)(6)................... No......................... Subpart HH does not require continuous
emissions monitoring.
Sec. 63.8(g)...................... No......................... Subpart HH specifies continuous monitoring
system data reduction requirements.
Sec. 63.9(a)...................... Yes
Sec. 63.9(b)(1)................... Yes
Sec. 63.9(b)(2)................... Yes........................ Sources are given 1 year (rather than 120
days) to submit this notification.
Sec. 63.9(b)(3)................... Yes
Sec. 63.9(b)(4)................... Yes
Sec. 63.9(b)(5)................... Yes
Sec. 63.9(c)...................... Yes
Sec. 63.9(d)...................... Yes
Sec. 63.9(e)...................... Yes
Sec. 63.9(f)...................... Yes
Sec. 63.9(g)...................... Yes
Sec. 63.9(h)(1) through (h)(3).... Yes
Sec. 63.9(h)(4)................... No......................... Section reserved.
Sec. 63.9(h)(5) through (h)(6).... Yes
Sec. 63.9(i)...................... Yes
Sec. 63.9(j)...................... Yes
Sec. 63.10(a)..................... Yes
Sec. 63.10(b)(1).................. Yes
Sec. 63.10(b)(2).................. Yes
Sec. 63.10(b)(3).................. No
Sec. 63.10(c)(1).................. Yes
Sec. 63.10(c)(2) through (c)(4)... No......................... Sections reserved.
Sec. 63.10(c)(5) Through (c)(8)... Yes
Sec. 63.10(c)(9).................. No......................... Section reserved.
Sec. 63.10(c)(10) through (c)(15). Yes
Sec. 63.10(d)(1).................. Yes
Sec. 63.10(d)(2).................. Yes
Sec. 63.10(d)(3).................. Yes
Sec. 63.10(d)(4).................. Yes
Sec. 63.10(d)(5).................. Yes........................ Subpart HH requires major sources to submit a
startup, shutdown and malfunction report semi-
annually.
Sec. 63.10(e)(1).................. Yes
Sec. 63.10(e)(2).................. Yes
Sec. 63.10(e)(3)(i)............... Yes........................ Subpart HH requires major sources to submit
Periodic Reports semi-annually.
Sec. 63.10(e)(3)(i)(A)............ Yes
Sec. 63.10(e)(3)(i)(B)............ Yes
Sec. 63.10(e)(3)(i)(C)............ No......................... Subpart HH does not require quarterly
reporting for excess emissions.
Sec. 63.10(e)(3)(ii) through Yes
(viii).
Sec. 63.10(f)..................... Yes
Sec. 63.11(a) and (b)............. Yes
Sec. 63.12(a) through (c)......... Yes
Sec. 63.13(a) through (c)......... Yes
Sec. 63.14(a) and (b)............. Yes
Sec. 63.15(a) and (b)............. Yes
----------------------------------------------------------------------------------------------------------------
PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS
FOR SOURCE CATEGORIES
3. Part 63 is amended by adding subpart HHH to read as follows:
Subpart HHH--National Emission Standards for Hazardous Air
Pollutants From Natural Gas Transmission and Storage Facilities
Sec.
63.1270 Applicability and designation of affected source.
63.1271 Definitions.
63.1272 Startups, shutdowns, and malfunctions.
63.1273 [Reserved]
63.1274 General standards.
63.1275 Glycol dehydration unit process vent standards.
63.1276-63.1280 [Reserved]
63.1281 Control equipment requirements.
63.1282 Test methods, compliance procedures, and compliance
demonstrations.
63.1283 Inspection and monitoring requirements.
63.1284 Recordkeeping requirements.
63.1285 Reporting requirements.
63.1286 Delegation of authority.
63.1287 Alternative means of emission limitation.
[[Page 32648]]
63.1288 [Reserved]
63.1289 [Reserved]
Appendix to Subpart HHH--Tables
Subpart HHH--National Emission Standards for Hazardous Air
Pollutants From Natural Gas Transmission and Storage Facilities
Sec. 63.1270 Applicability and designation of affected source.
(a) This subpart applies to owners and operators of natural gas
transmission and storage facilities that transport or store natural gas
prior to entering the pipeline to a local distribution company or to a
final end user (if there is no local distribution company), and that
are major sources of hazardous air pollutants (HAP) emissions as
determined using the maximum natural gas throughput calculated in
either paragraph (a)(1) or (a)(2) of this section and paragraphs (a)(3)
and (a)(4) of this section. A compressor station that transports
natural gas prior to the point of custody transfer, or to a natural gas
processing plant (if present) is considered a part of the oil and
natural gas production source category. A facility that is determined
to be an area source, based on emission estimates using the maximum
natural gas throughput calculated as specified in paragraph (a)(1) or
(a)(2) 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 (d)
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.
(1) Facilities that store natural gas or facilities that transport
and store natural gas shall determine major source status using the
maximum annual facility natural gas throughput calculated according to
paragraphs (a)(1)(i) through (a)(1)(iv) of this section.
(i) The owner or operator shall determine the number of hours to
complete the storage cycle for the facility. The storage cycle is the
number of hours for the injection cycle, calculated according to the
equation in paragraph (a)(1)(i)(A) of this section, plus the number of
hours for the withdrawal cycle, calculated according to the equation in
paragraph (a)(1)(i)(B) of this section.
(A) The hours for the facility injection cycle are determined
according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR17JN99.005
Where:
IC = Facility injection cycle in hours/cycle.
WGC = Working gas capacity in cubic meters. The working gas capacity is
defined as the maximum storage capacity minus the FERC cushion (as
defined in Sec. 63.1271).
IRmax = Maximum facility injection rate in cubic meters per
hour.
(B) The hours for the facility withdrawal cycle are determined
according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR17JN99.006
Where:
WC = Facility withdrawal cycle, hours/cycle.
WGC = Working gas capacity, cubic meters. The working gas capacity is
defined as the maximum storage capacity minus the FERC cushion (as
defined in Sec. 63.1271) and shall be the same value as used in
paragraph (a)(1)(i)(A) of this section.
WRmax = Maximum facility withdrawal rate in cubic meters per
hour.
(ii) The owner or operator shall calculate the number of storage
cycles for the facility per year according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR17JN99.007
Where:
Cycle = Number of storage cycles for the facility per year.
IC = Number of hours for a facility injection cycle, hours/cycle, as
calculated in paragraph (a)(1)(i)(A) of this section.
WC = Number of hours for a facility withdrawal cycle, hours/cycle, as
calculated in paragraph (a)(1)(i)(B) of this section.
(iii) The owner or operator shall calculate the facilitywide
maximum annual glycol dehydration unit hours of operation based on the
following equation:
Operation = Cycles x WC
Where:
Operation = Facilitywide maximum annual glycol dehydration unit hours
of operation (hr/yr).
Cycles = Number of storage cycles for the facility per year, as
calculated in paragraph (a)(1)(ii) of this section.
WC = Number of hours for a facility withdrawal cycle, hours/cycle, as
calculated in paragraph (a)(1)(i)(B) of this section.
(iv) The owner or operator shall calculate the maximum facilitywide
natural gas throughput based on the following equation:
Throughput = Operation x WRmax
Where:
Throughput = Maximum facilitywide natural gas throughput in cubic
meters per year.
Operation = Maximum facilitywide annual glycol dehydration unit hours
of operation in hours per year, as calculated in paragraph (a)(1)(iii)
of this section.
WRmax = Maximum facility withdrawal rate in cubic meters per
hour.
(2) Facilities that only transport natural gas shall calculate the
maximum natural gas throughput as the highest annual natural gas
throughput over the 5 years prior to June 17, 1999, multiplied by a
factor of 1.2.
(3) The owner or operator shall maintain records of the annual
facility natural gas throughput each year and upon request, submit such
records to the Administrator. If the facility annual natural gas
throughput increases above the maximum natural gas throughput
calculated in paragraph (a)(1) or (a)(2) of this section, the maximum
natural gas throughput must be recalculated using the higher throughput
multiplied by a factor of 1.2.
[[Page 32649]]
(4) The owner or operator shall determine the maximum values for
other parameters used to calculate potential emissions as the maximum
over the same period for which maximum throughput is determined as
specified in paragraph (a)(1) or (a)(2) of this section. These
parameters shall be based on an annual average or the highest single
measured value.
(b) The affected source is each glycol dehydration unit.
(c) The owner or operator of a facility that does not contain an
affected source, as specified in paragraph (b) of this section, is not
subject to the requirements of this subpart.
(d) The owner or operator of each affected source shall achieve
compliance with the provisions of this subpart by the following dates:
(1) The owner or operator of an affected source, the construction
or reconstruction of which commenced before February 6, 1998, shall
achieve compliance with this provisions of the 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.
(e) 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 permitting
requirements.
(f) Exemptions. A facility with a facilitywide actual annual
average natural gas throughput less than 28.3 thousand standard cubic
meters per day, where glycol dehydration units are the only HAP
emission source, is not subject to the requirements of this subpart.
Records shall be maintained as required in Sec. 63.10(b)(3).
Sec. 63.1271 Definitions.
All terms used in this subpart shall have the meaning given to them
in the Clean Air Act, subpart A of this part (General Provisions), and
in this section. If the same term is defined in subpart A and in this
section, it shall have the meaning given in this section for purposes
of this subpart.
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.
Compressor station means any permanent combination of compressors
that move natural gas at increased pressure from fields, in
transmission pipelines, or into storage.
Continuous recorder means a data recording device that either
records an instantaneous data value at least once every hour or records
hourly or more frequent block average values.
Control device means any equipment used for recovering or oxidizing
HAP or volatile organic compounds (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.
Custody transfer means the transfer of hydrocarbon liquids or
natural gas:
(1) After processing and/or treatment in the producing operations;
or
(2) From storage vessels or automatic transfer facilities, or other
equipment, including product loading racks, to pipelines or any other
forms of transportation.
Facility means any grouping of equipment where natural gas is
processed, compressed, or stored prior to entering a pipeline to a
local distribution company or (if there is no local distribution
company) to a final end user. Examples of a facility for this source
category are: an underground natural gas storage operation; or a
natural gas compressor station that receives natural gas via pipeline,
from an underground natural gas storage operation, or from a natural
gas processing plant. The emission points associated with these phases
include, but are not limited to, process vents. Processes that may have
vents include, but are not limited to, dehydration and compressor
station engines.
Facility, for the purpose of a major source determination, means
natural gas transmission and storage equipment that is located inside
the boundaries of an individual surface site (as defined in this
section) and is connected by ancillary equipment, such as gas flow
lines or power lines. Equipment that is part of a facility will
typically be located within close proximity to other equipment located
at the same facility. Natural gas transmission and storage equipment or
groupings of equipment located on different gas leases, mineral fee
tracts, lease tracts, subsurface unit areas, surface fee tracts, or
surface lease tracts shall not be considered part of the same facility.
Federal Energy Regulatory Commission Cushion or FERC Cushion means
the minimum natural gas capacity of a storage field as determined by
the Federal Energy Regulatory Commission.
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
[[Page 32650]]
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.
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, glycol dehydration unit 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 (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.
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.
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 pipeline compressor station or pump station
shall not be aggregated with emissions from other similar units,
whether or not such units are in a contiguous area or under common
control; and
(2) Emissions from processes, operations, and equipment that are
not part of the same facility, as defined in this section, shall not be
aggregated.
Natural gas means 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 transmission means the pipelines used for the long
distance transport of natural gas (excluding processing). Specific
equipment used in natural gas transmission includes the land, mains,
valves, meters, boosters, regulators, storage vessels, dehydrators,
compressors, and their driving units and appurtenances, and equipment
used for transporting gas from a production plant, delivery point of
purchased gas, gathering system, storage area, or other wholesale
source of gas to one or more distribution area(s).
No detectable emissions means no escape of HAP from a device or
system to the atmosphere as determined by:
(1) Instrument monitoring results in accordance with the
requirements of Sec. 63.1282(b); 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. 63.1282 (e) and (f).
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) .
Safety device means a device that meets both of the following
conditions: the device is not used for planned or routine venting of
liquids, gases, or fumes from the unit or equipment on which the device
is installed; and the device remains in a closed, sealed position at
all times except when an unplanned event requires that the device open
for the purpose of preventing physical damage or permanent deformation
of the unit or equipment on which the device is installed in accordance
with good engineering and safety practices for handling flammable,
combustible, explosive, or other hazardous materials. Examples of
unplanned events which may require a safety device to open include
failure of an essential equipment component or a sudden power outage.
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, produced water, or other liquid, and is
constructed primarily of non-earthen
[[Page 32651]]
materials (e.g., wood, concrete, steel, plastic) that provide
structural support.
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.
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
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.
Underground storage means the subsurface facilities utilized for
storing natural gas that has been transferred from its original
location for the primary purpose of load balancing, which is the
process of equalizing the receipt and delivery of natural gas.
Processes and operations that may be located at an underground storage
facility include, but are not limited to, compression and dehydration.
Sec. 63.1272 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 available.
(d) The owner or operator shall prepare a startup, shutdown, or
malfunction plan as required in Sec. 63.6(e)(3) except that the plan is
not required to be incorporated by reference into the source's title V
permit as specified in Sec. 63.6(e)(3)(i). Instead, the owner or
operator shall keep the plan on record as required by
Sec. 63.6(e)(3)(v). The failure of the plan to adequately minimize
emissions during the startup, shutdown, or malfunction does not shield
an owner or operator from enforcement actions.
Sec. 63.1273 [Reserved]
Sec. 63.1274 General standards.
(a) Table 2 of this subpart specifies the provisions of subpart A
(General Provisions) that apply and those that do not apply to owners
and operators of affected sources subject to this subpart.
(b) All reports required under this subpart shall be sent to the
Administrator at the appropriate address listed in Sec. 63.13. Reports
may be submitted on electronic media.
(c) Except as specified in paragraph (d) of this section, the owner
or operator of an affected source (i.e., glycol dehydration unit)
located at an existing or new major source of HAP emissions shall
comply with the requirements in this subpart as follows:
(1) The control requirements for glycol dehydration unit process
vents specified in Sec. 63.1275;
(2) The monitoring requirements specified in Sec. 63.1283, and
(3) The recordkeeping and reporting requirements specified in
Secs. 63.1284 and 63.1285.
(d) Exemptions. The owner or operator is exempt from the
requirements of paragraph (c) of this section if the criteria listed in
paragraph (d)(1) or (d)(2) of this section are met. Records of the
determination of these criteria must be maintained as required in
Sec. 63.1284(d) of this subpart.
(1) The actual annual average flow of gas to the glycol dehydration
unit is less than 283 thousand standard cubic meters per day, as
determined by the procedures specified in Sec. 63.1282(a)(1) of this
subpart; or
(2) The actual average emissions of benzene from the glycol
dehydration unit process vents to the atmosphere are less than 0.90
megagram per year as determined by the procedures specified in
Sec. 63.1282(a)(2) of this subpart.
(e) Each owner or operator of a major HAP source subject to this
subpart is required to apply for a part 70 or part 71 operating permit
from the appropriate permitting authority. If the Administrator has
approved a State operating permit program under part 70, the permit
shall be obtained from the State authority. If a State operating permit
program has not been approved, the owner or operator shall apply to the
EPA Regional Office pursuant to part 71.
(f) [Reserved]
(g) In all cases where the provisions of this subpart require an
owner or operator to repair leaks by a specified time after the leak is
detected, it is a violation of this standard to fail to take action to
repair the leak(s) within the specified time. If action is taken to
repair the leak(s) within the specified time, failure of that action to
successfully repair the leak(s) is not a violation of this standard.
However, if the repairs are unsuccessful, a leak is detected and the
owner or operator shall take further action as required by the
applicable provisions of this subpart.
Sec. 63.1275 Glycol dehydration unit process vent standards.
(a) This section applies to each glycol dehydration unit, subject
to this subpart, with an actual annual average natural gas flowrate
equal to or greater than 283 thousand standard cubic meters per day and
with actual average benzene glycol dehydration unit process vent
emissions equal to or greater than 0.90 megagrams per year.
(b) Except as provided in paragraph (c) of this section, an owner
or operator of a glycol dehydration unit process vent shall comply with
the requirements specified in paragraphs (b)(1) and (b)(2) of this
section.
(1) For each glycol dehydration unit process vent, the owner or
operator shall control air emissions by either paragraph (b)(1)(i) or
(b)(1)(ii) of this section.
[[Page 32652]]
(i) The owner or operator shall connect the process vent to a
control device or a combination of control devices through a closed-
vent system. The closed-vent system shall be designed and operated in
accordance with the requirements of Sec. 63.1281(c). The control
device(s) shall be designed and operated in accordance with the
requirements of Sec. 63.1281(d).
(ii) The owner or operator shall connect the process vent to a
control device or a combination of control devices through a closed-
vent system and the outlet benzene emissions from the control device(s)
shall be less than 0.90 megagrams per year. The closed-vent system
shall be designed and operated in accordance with the requirements of
Sec. 63.1281(c). The control device(s) shall be designed and operated
in accordance with the requirements of Sec. 63.1281(d), except that the
performance requirements specified in Sec. 63.1281(d)(1)(i) and (ii) do
not apply.
(2) One or more safety devices that vent directly to the atmosphere
may be used on the air emission control equipment installed to comply
with paragraph (b)(1) of this section.
(c) As an alternative to the requirements of paragraph (b) of this
section, the owner or operator may comply with one of the following:
(1) The owner or operator shall control air emissions by connecting
the process vent to a process natural gas line.
(2) The owner or operator shall demonstrate, to the Administrator's
satisfaction, that the total HAP emissions to the atmosphere from the
glycol dehydration unit process vent are reduced by 95.0 percent
through process modifications or a combination of process modifications
and one or more control devices, in accordance with the requirements
specified in Sec. 63.1281(e).
(3) Control of HAP emissions from a GCG separator (flash tank) vent
is not required if the owner or operator demonstrates, to the
Administrator's satisfaction, that total emissions to the atmosphere
from the glycol dehydration unit process vent are reduced by one of the
levels specified in paragraphs (c)(3)(i) through (c)(3)(ii), through
the installation and operation of controls as specified in paragraph
(b) (1) of this section.
(i) HAP emissions are reduced by 95.0 percent or more.
(ii) Benzene emissions are reduced to a level less than 0.90
megagrams per year.
Sec. 63.1276-Sec. 63.1280 [Reserved]
Sec. 63.1281 Control equipment requirements.
(a) This section applies to each closed-vent system and control
device installed and operated by the owner or operator to control air
emissions as required by the provisions of this subpart. Compliance
with paragraphs (c) and (d) of this section will be determined by
review of the records required by Sec. 63.1284, the reports required by
Sec. 63.1285, by review of performance test results, and by
inspections.
(b) [Reserved]
(c) Closed-vent system requirements. (1) The closed-vent system
shall route all gases, vapors, and fumes emitted from the material in a
HAP emissions unit to a control device that meets the requirements
specified in paragraph (d) of this section.
(2) The closed-vent system shall be designed and operated with no
detectable emissions.
(3) If the closed-vent system contains one or more bypass devices
that could be used to divert all or a portion of the gases, vapors, or
fumes from entering the control device, the owner or operator shall
meet the requirements specified in paragraphs (c)(3)(i) and (c)(3)(ii)
of this section.
(i) For each bypass device, except as provided for in paragraph
(c)(3)(ii) of this section, the owner or operator shall either:
(A) Properly install, calibrate, maintain, and operate a flow
indicator at the inlet to the bypass device that could divert the
stream away from the control device to the atmosphere that takes a
reading at least once every 15 minutes, and that sounds an alarm when
the bypass device is open such that the stream is being, or could be,
diverted away from the control device to the atmosphere; or
(B) Secure the bypass device valve installed at the inlet to the
bypass device in the non-diverting position using a car-seal or a lock-
and-key type configuration. The owner or operator shall visually
inspect the seal or closure mechanism at least once every month to
verify that the valve is maintained in the non-diverting position and
the vent stream is not diverted through the bypass device.
(ii) Low leg drains, high point bleeds, analyzer vents, open-ended
valves or lines, and safety devices are not subject to the requirements
of paragraph (c)(3)(i) of this section.
(d) Control device requirements. (1) The control device used to
reduce HAP emissions in accordance with the standards of this subpart
shall be one of the control devices specified in paragraphs (d)(1)(i)
through (iii) of this section.
(i) An enclosed combustion device (e.g., thermal vapor incinerator,
catalytic vapor incinerator, boiler, or process heater) that is
designed and operated in accordance with one of the following
performance requirements:
(A) Reduces the mass content of either TOC or total HAP in the
gases vented to the device by 95.0 percent by weight or greater, as
determined in accordance with the requirements of Sec. 63.1282(d);
(B) Reduces the concentration of either TOC or total HAP in the
exhaust gases at the outlet to the device to a level equal to or less
than 20 parts per million by volume on a dry basis corrected to 3
percent oxygen as determined in accordance with the requirements of
Sec. 63.1282(d); or
(C) Operates at a minimum residence time of 0.5 second at a minimum
temperature of 760 deg.C.
(D) If a boiler or process heater is used as the control device,
then the vent stream shall be introduced into the flame zone of the
boiler or process heater.
(ii) A vapor recovery device (e.g., carbon adsorption system or
condenser) or other control device that is designed and operated to
reduce the mass content of either TOC or total HAP in the gases vented
to the device by 95.0 percent by weight or greater as determined in
accordance with the requirements of Sec. 63.1282(d).
(iii) A flare that is designed and operated in accordance with the
requirements of Sec. 63.11(b).
(2) [Reserved]
(3) The owner or operator shall demonstrate that a control device
achieves the performance requirements of paragraph (d)(1) of this
section by following the procedures specified in Sec. 63.1282(d).
(4) The owner or operator shall operate each control device in
accordance with the requirements specified in paragraphs (d)(4)(i) and
(ii) of this section.
(i) Each control device used to comply with this subpart shall be
operating at all times when gases, vapors, and fumes are vented from
the emissions unit or units through the closed-vent system to the
control device, as required under Sec. 63.1275, except when maintenance
or repair of a unit cannot be completed without a shutdown of the
control device. An owner or operator may vent more than one unit to a
control device used to comply with this subpart.
(ii) For each control device monitored in accordance with the
requirements of
[[Page 32653]]
Sec. 63.1283(d), the owner or operator shall demonstrate compliance
according to the requirements of Sec. 63.1282(e), or (f) as applicable.
(5) For each carbon adsorption system used as a control device to
meet the requirements of paragraph (d)(1) of this section, the owner or
operator shall manage the carbon as follows:
(i) Following the initial startup of the control device, all carbon
in the control device shall be replaced with fresh carbon on a regular,
predetermined time interval that is no longer than the carbon service
life established for the carbon adsorption system.
(ii) The spent carbon removed from the carbon adsorption system
shall be either regenerated, reactivated, or burned in one of the units
specified in paragraphs (d)(5)(ii)(A) through (d)(5)(ii)(G) of this
section.
(A) Regenerated or reactivated in a thermal treatment unit for
which the owner or operator has been issued a final permit under 40 CFR
part 270 that implements the requirements of 40 CFR part 264, subpart
X.
(B) Regenerated or reactivated in a thermal treatment unit equipped
with and operating organic air emission controls in accordance with
this section.
(C) Regenerated or reactivated in a thermal treatment unit equipped
with and operating organic air emission controls in accordance with a
national emissions standard for HAP under another subpart in 40 CFR
part 61 or this part.
(D) Burned in a hazardous waste incinerator for which the owner or
operator has been issued a final permit under 40 CFR part 270 that
implements the requirements of 40 CFR part 264, subpart O.
(E) Burned in a hazardous waste incinerator which the owner or
operator has designed and operates in accordance with the requirements
of 40 CFR part 265, subpart O.
(F) Burned in a boiler or industrial furnace for which the owner or
operator has been issued a final permit under 40 CFR part 270 that
implements the requirements of 40 CFR part 266, subpart H.
(G) Burned in a boiler or industrial furnace which the owner or
operator has designed and operates in accordance with the interim
status requirements of 40 CFR part 266, subpart H.
(e) Process modification requirements. Each owner or operator that
chooses to comply with Sec. 63.1275(c)(2) shall meet the requirements
specified in paragraphs (e)(1) through (e)(3) of this section.
(1) The owner or operator shall determine glycol dehydration unit
baseline operations (as defined in Sec. 63.1271). Records of glycol
dehydration unit baseline operations shall be retained as required
under Sec. 63.1284(b)(9).
(2) The owner or operator shall document, to the Administrator's
satisfaction, the conditions for which glycol dehydration unit baseline
operations shall be modified to achieve the 95.0 percent overall HAP
emission reduction, either through process modifications or through a
combination of process modifications and one or more control devices.
If a combination of process modifications and one or more control
devices are used, the owner or operator shall also establish the
percent HAP reduction to be achieved by the control device to achieve
an overall HAP emission reduction of 95.0 percent for the glycol
dehydration unit process vent. Only modifications in glycol dehydration
unit operations directly related to process changes, including, but not
limited to, changes in glycol circulation rate or glycol-HAP
absorbency, shall be allowed. Changes in the inlet gas characteristics
or natural gas throughput rate shall not be considered in determining
the overall HAP emission reduction.
(3) The owner or operator that achieves a 95.0 percent HAP emission
reduction using process modifications alone shall comply with paragraph
(e)(3)(i) of this section. The owner or operator that achieves a 95.0
percent HAP emission reduction using a combination of process
modifications and one or more control devices shall comply with
paragraphs (e)(3)(i) and (e)(3)(ii) of this section.
(i) The owner or operator shall maintain records, as required in
Sec. 63.1284(b)(10), that the facility continues to operate in
accordance with the conditions specified under paragraph (e)(2) of this
section.
(ii) The owner or operator shall comply with the control device
requirements specified in paragraph (d) of this section, except that
the emission reduction achieved shall be the emission reduction
specified in paragraph (e)(2) of this section.
Sec. 63.1282 Test methods, compliance procedures, and compliance
demonstrations.
(a) Determination of glycol dehydration unit flowrate or benzene
emissions. The procedures of this paragraph shall be used by an owner
or operator to determine glycol dehydration unit natural gas flowrate
or benzene emissions to meet the criteria for the exemption from
control requirements under Sec. 63.1274(d).
(1) The determination of actual flowrate of natural gas to a glycol
dehydration unit shall be made using the procedures of either paragraph
(a)(1)(i) or (a)(1)(ii) of this section.
(i) The owner or operator shall install and operate a monitoring
instrument that directly measures natural gas flowrate to the glycol
dehydration unit with an accuracy of plus or minus 2 percent or better.
The owner or operator shall convert the annual natural gas flowrate to
a daily average by dividing the annual flowrate by the number of days
per year the glycol dehydration unit processed natural gas.
(ii) The owner or operator shall document, to the Administrator's
satisfaction, that the actual annual average natural gas flowrate to
the glycol dehydration unit is less than 85 thousand standard cubic
meters per day.
(2) The determination of actual average benzene emissions from a
glycol dehydration unit shall be made using the procedures of either
paragraph (a)(2)(i) or (a)(2)(ii) of this section. Emissions shall be
determined either uncontrolled or with federally enforceable controls
in place.
(i) The owner or operator shall determine actual average benzene
emissions using the model GRI-GLYCalcTM, Version 3.0 or
higher, and the procedures presented in the associated GRI-
GLYCalcTM Technical Reference Manual. Inputs to the model
shall be representative of actual operating conditions of the glycol
dehydration unit and may be determined using the procedures documented
in the Gas Research Institute (GRI) report entitled ``Atmospheric Rich/
Lean Method for Determining Glycol Dehydrator Emissions'' (GRI-95/
0368.1); or
(ii) The owner or operator shall determine an average mass rate of
benzene emissions in kilograms per hour through direct measurement by
performing three runs of Method 18 in 40 CFR part 60, appendix A (or an
equivalent method), and averaging the results of the three runs. Annual
emissions in kilograms per year shall be determined by multiplying the
mass rate by the number of hours the unit is operated per year. This
result shall be converted to megagrams per year.
(b) No detectable emissions test procedure. (1) The procedure shall
be conducted in accordance with Method 21, 40 CFR part 60, appendix A.
(2) The detection instrument shall meet the performance criteria of
Method 21, 40 CFR part 60, appendix A, except the instrument response
factor criteria
[[Page 32654]]
in section 3.1.2(a) of Method 21 shall be for the average composition
of the fluid, and not for each individual organic compound in the
stream.
(3) The detection instrument shall be calibrated before use on each
day of its use by the procedures specified in Method 21, 40 CFR part
60, appendix A.
(4) Calibration gases shall be as follows:
(i) Zero air (less than 10 parts per million by volume hydrocarbon
in air); and
(ii) A mixture of methane in air at a methane concentration of less
than 10,000 parts per million by volume.
(5) An owner or operator may choose to adjust or not adjust the
detection instrument readings to account for the background organic
concentration level. If an owner or operator chooses to adjust the
instrument readings for the background level, the background level
value must be determined according to the procedures in Method 21 of 40
CFR part 60, appendix A.
(6)(i) Except as provided in paragraph (b)(6)(i) of this section,
the detection instrument shall meet the performance criteria of Method
21 of 40 CFR part 60, appendix A, except the instrument response factor
criteria in section 3.1.2(a) of Method 21 shall be for the average
composition of the process fluid not each individual volatile organic
compound in the stream. For process streams that contain nitrogen, air,
or other inerts which are not organic hazardous air pollutants or
volatile organic compounds, the average stream response factor shall be
calculated on an inert-free basis.
(ii) If no instrument is available at the facility that will meet
the performance criteria specified in paragraph (b)(6)(i) of this
section, the instrument readings may be adjusted by multiplying by the
average response factor of the process fluid, calculated on an inert-
free basis as described in paragraph (b)(6)(i) of this section.
(7) An owner or operator must determine if a potential leak
interface operates with no detectable emissions using the applicable
procedure specified in paragraph (b)(7)(i) or (b)(7)(ii) of this
section.
(i) If an owner or operator chooses not to adjust the detection
instrument readings for the background organic concentration level,
then the maximum organic concentration value measured by the detection
instrument is compared directly to the applicable value for the
potential leak interface as specified in paragraph (b)(8) of this
section.
(ii) If an owner or operator chooses to adjust the detection
instrument readings for the background organic concentration level, the
value of the arithmetic difference between the maximum organic
concentration value measured by the instrument and the background
organic concentration value as determined in paragraph (b)(5) of this
section is compared with the applicable value for the potential leak
interface as specified in paragraph (b)(8) of this section.
(8) A potential leak interface is determined to operate with no
detectable organic emissions if the organic concentration value
determined in paragraph (b)(7) is less than 500 parts per million by
volume.
(c) [Reserved]
(d) Control device performance test procedures. This paragraph
applies to the performance testing of control devices. The owners or
operators shall demonstrate that a control device achieves the
performance requirements of Sec. 63.1281(d)(1) or (e)(3)(ii) using
either a performance test as specified in paragraph (d)(3) of this
section or a design analysis as specified in paragraph (d)(4) of this
section. The owner or operator may elect to use the alternative
procedures in paragraph (d)(5) of this section for performance testing
of a condenser used to control emissions from a glycol dehydration unit
process vent.
(1) The following control devices are exempt from the requirements
to conduct performance tests and design analyses under this section:
(i) A flare that is designed and operated in accordance with
Sec. 63.11(b);
(ii) A boiler or process heater with a design heat input capacity
of 44 megawatts or greater;
(iii) A boiler or process heater into which the vent stream is
introduced with the primary fuel or is used as the primary fuel;
(iv) A boiler or process heater burning hazardous waste for which
the owner or operator has either been issued a final permit under 40
CFR part 270 and complies with the requirements of 40 CFR part 266,
subpart H, or has certified compliance with the interim status
requirements of 40 CFR part 266, subpart H;
(v) A hazardous waste incinerator for which the owner or operator
has been issued a final permit under 40 CFR part 270 and complies with
the requirements of 40 CFR part 264, subpart O, or has certified
compliance with the interim status requirements of 40 CFR part 265,
subpart O.
(vi) A control device for which a performance test was conducted
for determining compliance with a regulation promulgated by the EPA,
and the test was conducted using the same methods specified in this
section, and either no process changes have been made since the test,
or the owner or operator can demonstrate that the results of the
performance test, with or without adjustments, reliably demonstrate
compliance despite process changes.
(2) An owner or operator shall design and operate each flare in
accordance with the requirements specified in Sec. 63.11(b) and in
paragraphs (d)(2)(i) and (d)(2)(ii) of this section.
(i) The compliance determination shall be conducted using Method 22
of 40 CFR part 60, appendix A, to determine visible emissions.
(ii) An owner or operator is not required to conduct a performance
test to determine percent emission reduction or outlet organic HAP or
TOC concentration when a flare is used.
(3) For a performance test conducted to demonstrate that a control
device meets the requirements of Sec. 63.1281(d)(1) or (e)(3)(ii), the
owner or operator shall use the test methods and procedures specified
in paragraphs (d)(3)(i) through (d)(3)(iv) of this section. The
performance test shall be conducted according to the schedule specified
in Sec. 63.7(a)(2), and the results of the performance test shall be
submitted in the Notification of Compliance Status Report as required
in Sec. 63.1285(d)(1)(ii).
(i) Method 1 or 1A, 40 CFR part 60, appendix A, as appropriate,
shall be used for selection of the sampling sites specified in
paragraphs (d)(3)(i)(A) and (B) of this section. Any references to
particulate mentioned in Methods 1 and 1A do not apply to this section.
(A) To determine compliance with the control device percent
reduction requirements specified in
Sec. 63.1281(d)(1)(i)(A),(d)(1)(ii), or (e)(3)(ii), sampling sites
shall be located at the inlet of the first control device and at the
outlet of the final control device.
(B) To determine compliance with the enclosed combustion device
total HAP concentration limit specified in Sec. 63.1281(d)(1)(i)(B),
the sampling site shall be located at the outlet of the device.
(ii) The gas volumetric flowrate shall be determined using Method
2, 2A, 2C, or 2D, 40 CFR part 60, appendix A, as appropriate.
(iii) To determine compliance with the control device percent
reduction performance requirement in Sec. 63.1281(d)(1)(i)(A),
63.1281(d)(1)(ii), or 63.1281(e)(3)(ii), the owner or operator shall
use either Method 18, 40 CFR part 60, appendix A, or Method 25A, 40 CFR
part 60, appendix A;
[[Page 32655]]
alternatively, any other method or data that have been validated
according to the applicable procedures in Method 301 of appendix A of
this part may be used. The following procedures shall be used to
calculate the percentage of reduction:
(A) The minimum sampling time for each run shall be 1 hour in which
either an integrated sample or a minimum of four grab samples shall be
taken. If grab sampling is used, then the samples shall be taken at
approximately equal intervals in time, such as 15-minute intervals
during the run.
(B) The mass rate of either TOC (minus methane and ethane) or total
HAP (Ei, Eo) shall be computed.
(1) The following equations shall be used:
[GRAPHIC] [TIFF OMITTED] TR17JN99.008
[GRAPHIC] [TIFF OMITTED] TR17JN99.009
Where:
Cij, Coj = Concentration of sample component j of
the gas stream at the inlet and outlet of the control device,
respectively, dry basis, parts per million by volume.
Ei, Eo = Mass rate of TOC (minus methane and
ethane) or total HAP at the inlet and outlet of the control device,
respectively, dry basis, kilogram per hour.
Mij, Moj = Molecular weight of sample component j
of the gas stream at the inlet and outlet of the control device,
respectively, gram/gram-mole.
Qi, Qo = Flowrate of gas stream at the inlet and
outlet of the control device, respectively, dry standard cubic meter
per minute.
K2 = Constant, 2.494x10 -6 (parts per million)
-1 (gram-mole per standard cubic meter) (kilogram/gram)
(minute/hour), where standard temperature is 20 deg.C.
(2) When the TOC mass rate is calculated, all organic compounds
(minus methane and ethane) measured by Method 18, of 40 CFR part 60,
appendix A; or Method 25A, 40 CFR part 60, appendix A, shall be summed
using the equations in paragraph (d)(3)(iii)(B)(1) of this section.
(3) When the total HAP mass rate is calculated, only HAP chemicals
listed in Table 1 of this subpart shall be summed using the equations
in paragraph (d)(3)(iii)(B)(1) of this section.
(C) The percentage of reduction in TOC (minus methane and ethane)
or total HAP shall be calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR17JN99.010
Where:
Rcd = Control efficiency of control device, percent.
Ei = Mass rate of TOC (minus methane and ethane) or total
HAP at the inlet to the control device as calculated under paragraph
(d)(3)(iii)(B) of this section, kilograms TOC per hour or kilograms HAP
per hour.
Eo = Mass rate of TOC (minus methane and ethane) or total
HAP at the outlet of the control device, as calculated under paragraph
(d)(3)(iii)(B) of this section, kilograms TOC per hour or kilograms HAP
per hour.
(D) If the vent stream entering a boiler or process heater with a
design capacity less than 44 megawatts is introduced with the
combustion air or as a secondary fuel, the weight-percentage of
reduction of total HAP or TOC (minus methane and ethane) across the
device shall be determined by comparing the TOC (minus methane and
ethane) or total HAP in all combusted vent streams and primary and
secondary fuels with the TOC (minus methane and ethane) or total HAP
exiting the device, respectively.
(iv) To determine compliance with the enclosed combustion device
total HAP concentration limit specified in Sec. 63.1281(d)(1)(i)(B),
the owner or operator shall use either Method 18, 40 CFR part 60,
appendix A; or Method 25A, 40 CFR part 60, appendix A, to measure
either TOC (minus methane and ethane) or total HAP. Alternatively, any
other method or data that have been validated according to Method 301
of appendix A of this part, may be used. The following procedures shall
be used to calculate parts per million by volume concentration,
corrected to 3 percent oxygen:
(A) The minimum sampling time for each run shall be 1 hour in which
either an integrated sample or a minimum of four grab samples shall be
taken. If grab sampling is used, then the samples shall be taken at
approximately equal intervals in time, such as 15-minute intervals
during the run.
(B) The TOC concentration or total HAP concentration shall be
calculated according to paragraph (d)(3)(iv)(B)(1) or (d)(3)(iv)(B)(2)
of this section.
(1) The TOC concentration (CTOC) is the sum of the
concentrations of the individual components and shall be computed for
each run using the following equation:
[GRAPHIC] [TIFF OMITTED] TR17JN99.011
Where:
CTOC = Concentration of total organic compounds minus
methane and ethane, dry basis, parts per million by volume.
Cji = Concentration of sample components j of sample i, dry
basis, parts per million by volume.
n = Number of components in the sample.
x = Number of samples in the sample run.
(2) The total HAP concentration (CHAP) shall be computed
according to the equation in paragraph (d)(3)(iv)(B)(1) of this
section, except that only HAP chemicals listed in Table 1 of this
subpart shall be summed.
(C) The TOC concentration or total HAP concentration shall be
corrected to 3 percent oxygen as follows:
(1) The emission rate correction factor for excess air, integrated
sampling and analysis procedures of Method 3B, 40 CFR part 60, appendix
A, shall be used to determine the oxygen concentration
(%O2d). The samples shall be taken during the same time that
the samples are taken for determining TOC concentration or total HAP
concentration.
(2) The concentration corrected to 3 percent oxygen (Cc)
shall be computed using the following equation:
[GRAPHIC] [TIFF OMITTED] TR17JN99.012
Where:
Cc = TOC concentration of total HAP concentration corrected
to 3 percent oxygen, dry basis, parts per million by volume.
Cm = TOC concentration or total HAP concentration, dry
basis, parts per million by volume.
%O2d = Concentration of oxygen, dry basis, percent by
volume.
(4) For a design analysis conducted to meet the requirements of
Sec. 63.1281(d)(1) or (e)(3)(ii), the owner or operator shall meet the
requirements specified in paragraphs (d)(4)(i) and (d)(4)(ii) of this
section. Documentation of the design analysis shall be submitted as a
part of the Notification of Compliance Status Report as required in
Sec. 63.1285(d)(1)(i).
(i) The design analysis shall include analysis of the vent stream
characteristics and control device
[[Page 32656]]
operating parameters for the applicable control device as specified in
paragraphs (d)(4)(i) (A) through (F) of this section.
(A) For a thermal vapor incinerator, the design analysis shall
include the vent stream composition, constituent concentrations, and
flowrate and shall establish the design minimum and average
temperatures in the combustion zone and the combustion zone residence
time.
(B) For a catalytic vapor incinerator, the design analysis shall
include the vent stream composition, constituent concentrations, and
flowrate and shall establish the design minimum and average
temperatures across the catalyst bed inlet and outlet, and the design
service life of the catalyst.
(C) For a boiler or process heater, the design analysis shall
include the vent stream composition, constituent concentrations, and
flowrate; shall establish the design minimum and average flame zone
temperatures and combustion zone residence time; and shall describe the
method and location where the vent stream is introduced into the flame
zone.
(D) For a condenser, the design analysis shall include the vent
stream composition, constituent concentrations, flowrate, relative
humidity, and temperature, and shall establish the design outlet
organic compound concentration level, design average temperature of the
condenser exhaust vent stream, and the design average temperatures of
the coolant fluid at the condenser inlet and outlet. As an alternative
to the design analysis, an owner or operator may elect to use the
procedures specified in paragraph (d)(5) of this section.
(E) For a regenerable carbon adsorption, the design analysis shall
include the vent stream composition, constituent concentrations,
flowrate, relative humidity, and temperature, and shall establish the
design exhaust vent stream organic compound concentration level,
adsorption cycle time, number and capacity of carbon beds, type and
working capacity of activated carbon used for the carbon beds, design
total regeneration stream flow over the period of each complete carbon
bed regeneration cycle, design carbon bed temperature after
regeneration, design carbon bed regeneration time, and design service
life of the carbon.
(F) For a nonregenerable carbon adsorption system, such as a carbon
canister, the design analysis shall include the vent stream
composition, constituent concentrations, flowrate, relative humidity,
and temperature, and shall establish the design exhaust vent stream
organic compound concentration level, capacity of the carbon bed, type
and working capacity of activated carbon used for the carbon bed, and
design carbon replacement interval based on the total carbon working
capacity of the control device and source operating schedule. In
addition, these systems will incorporate dual carbon canisters in case
of emission breakthrough occurring in one canister.
(ii) If the owner or operator and the Administrator do not agree on
a demonstration of control device performance using a design analysis,
then the disagreement shall be resolved using the results of a
performance test performed by the owner or operator in accordance with
the requirements of paragraph (d)(3) of this section. The Administrator
may choose to have an authorized representative observe the performance
test.
(5) As an alternative to the procedures in paragraphs (d)(3) and
(d)(4)(i)(D) of this section, an owner or operator may elect to use the
procedures documented in the GRI report entitled, ``Atmospheric Rich/
Lean Method for Determining Glycol Dehydrator Emissions,'' (GRI-95/
0368.1) as inputs for the model GRI-GLYCalcTM, Version 3.0
or higher, to determine condenser performance.
(e) Compliance demonstration for control devices performance
requirements. This paragraph applies to the demonstration of compliance
with the control device performance requirements specified in
Sec. 63.1281(d)(1) and (e)(3)(ii). Compliance shall be demonstrated
using the requirements in paragraphs (e)(1) through (e)(3) of this
section. As an alternative, an owner or operator that installs a
condenser as the control device to achieve the requirements specified
in Sec. 63.1281(d)(2)(ii) or Sec. 63.1275(c)(2), may demonstrate
compliance according to paragraph (f) of this section. An owner or
operator may switch between compliance with paragraph (e) of this
section and compliance with paragraph (f) of this section only after at
least 1 year of operation in compliance with the selected approach.
Notification of such a change in the compliance method shall be
reported in the next Periodic Report, as required in Sec. 63.1285(e),
following the change.
(1) The owner or operator shall establish a site specific maximum
or minimum monitoring parameter value (as appropriate) according to the
requirements of Sec. 63.1283(d)(5)(i).
(2) The owner or operator shall calculate the daily average of the
applicable monitored parameter in accordance with Sec. 63.1283(d)(4).
(3) Compliance is achieved when the daily average of the monitoring
parameter value calculated under paragraph (e)(2) of this section is
either equal to or greater than the minimum or equal to or less than
the maximum monitoring value established under paragraph (e)(1) of this
section.
(f) Compliance demonstration with percent reduction performance
requirements--condensers. This paragraph applies to the demonstration
of compliance with the performance requirements specified in
Sec. 63.1281(d)(1)(ii) for condensers. Compliance shall be demonstrated
using the procedures in paragraphs (f)(1) through (f)(3) of this
section.
(1) The owner or operator shall establish a site-specific condenser
performance curve according to the procedures specified in
Sec. 63.1283(d)(5)(ii).
(2) Compliance with the percent reduction requirement in
Sec. 63.1281(d)(1)(ii) or Sec. 63.1275(c)(2) shall be demonstrated by
the procedures in paragraphs (f)(2)(i) through (f)(2)(iii) of this
section.
(i) The owner or operator must calculate the daily average
condenser outlet temperature in accordance with Sec. 63.1283(d)(4).
(ii) The owner or operator shall determine the condenser efficiency
for the current operating day using the daily average condenser outlet
temperature calculated in paragraph (f)(2)(i) of this section and the
condenser performance curve established in paragraph (f)(1) of this
section.
(iii) Except as provided in paragraphs (f)(2)(iii) (A), (B), and
(D) of this section, at the end of each operating day the owner or
operator shall calculate the 30-day average HAP emission reduction from
the condenser efficiencies determined in paragraph (f)(2)(ii) of this
section for the preceding 30 operating days. If the owner or operator
uses a combination of process modifications and a condenser in
accordance with the requirements of Sec. 63.1275(c)(2), the 30-day
average HAP emission reduction shall be calculated using the emission
reduction achieved through process modifications and the condenser
efficiency determined in paragraph (f)(2)(ii) of this section, both for
the preceding 30 operating days.
(A) After the compliance date specified in Sec. 63.1270(f), an
owner or operator of a facility that stores natural gas that has less
than 30 days of data for determining the average HAP emission
reduction, shall calculate the cumulative average at the end of the
withdrawal season, each season, until 30 days of condenser operating
data are
[[Page 32657]]
accumulated. For a facility that does not store natural gas, the owner
or operator that has less than 30 days of data for determining average
HAP emission reduction, shall calculate the cumulative average at the
end of the calendar year, each year, until 30 days of condenser
operating data are accumulated.
(B) After the compliance date specified in Sec. 63.1270(f), an
owner or operator that has less than 30 days of data for determining
the average HAP emission reduction, compliance is achieved if the
average HAP emission reduction calculated in paragraph (f)(2)(iii)(A)
of this section, is equal to or greater than 95.0 percent.
(C) For the purposes of this subpart, a withdrawal season begins
the first time gas is withdrawn from the storage field after July 1 of
the calendar year and ends on June 30 of the next calendar year.
(D) Glycol dehydration units that are operated continuously have
the option of complying with the requirements specified in 40 CFR
63.772(g).
(3) Compliance is achieved with the emission limitation specified
in Sec. 63.1281(d)(1)(ii) or Sec. 63.1275(c)(2) if the average HAP
emission reduction calculated in paragraph (f)(2)(iii) of this section
is equal to or greater than 95.0 percent.
Sec. 63.1283 Inspection and monitoring requirements.
(a) This section applies to an owner or operator using air emission
controls in accordance with the requirements of Sec. 63.1275.
(b) [Reserved]
(c) Closed-vent system inspection and monitoring requirements. (1)
For each closed-vent system required to comply with this section, the
owner or operator shall comply with the requirements of paragraphs
(c)(2) through (7) of this section.
(2) Except as provided in paragraphs (c) (5) and (6) of this
section, each closed-vent system shall be inspected according to the
procedures and schedule specified in paragraphs (c)(2) (i) and (ii) of
this section.
(i) For each closed-vent system joints, seams, or other connections
that are permanently or semi-permanently sealed (e.g., a welded joint
between two sections of hard piping or a bolted or gasketed ducting
flange), the owner or operator shall:
(A) Conduct an initial inspection according to the procedures
specified in Sec. 63.1282(b) to demonstrate that the closed-vent system
operates with no detectable emissions.
(B) Conduct annual visual inspections for defects that could result
in air emissions. Defects include, but are not limited to, visible
cracks, holes, or gaps in piping; loose connections; or broken or
missing caps or other closure devices. The owner or operator shall
monitor a component or connection using the procedures specified in
Sec. 63.1282(b) to demonstrate that it operates with no detectable
emissions following any time the component or connection is repaired or
replaced or the connection is unsealed.
(ii) For closed-vent system components other than those specified
in paragraph (c)(2)(i) of this section, the owner or operator shall:
(A) Conduct an initial inspection according to the procedures
specified in Sec. 63.1282(b) to demonstrate that the closed-vent system
operates with no detectable emissions.
(B) Conduct annual inspections according to the procedures
specified in Sec. 63.1282(b) to demonstrate that the components or
connections operate with no detectable emissions.
(C) Conduct annual visual inspections for defects that could result
in air emissions. Defects include, but are not limited to, visible
cracks, holes, or gaps in ductwork; loose connections; or broken or
missing caps or other closure devices.
(3) In the event that a leak or defect is detected, the owner or
operator shall repair the leak or defect as soon as practicable, except
as provided in paragraph (c)(4) of this section.
(i) A first attempt at repair shall be made no later than 5
calendar days after the leak is detected.
(ii) Repair shall be completed no later than 15 calendar days after
the leak is detected.
(4) Delay of repair of a closed-vent system for which leaks or
defects have been detected is allowed if the repair is technically
infeasible without a shutdown, as defined in Sec. 63.1271, or if the
owner or operator determines that emissions resulting from immediate
repair would be greater than the fugitive emissions likely to result
from delay of repair. Repair of such equipment shall be completed by
the end of the next shutdown.
(5) Any parts of the closed-vent system or cover that are
designated, as described in paragraphs (c)(5) (i) and (ii) of this
section, as unsafe to inspect are exempt from the inspection
requirements of paragraphs (c)(2) (i) and (ii) of this section if:
(i) The owner or operator determines that the equipment is unsafe
to inspect because inspecting personnel would be exposed to an imminent
or potential danger as a consequence of complying with paragraph (c)(2)
(i) or (ii) of this section; and
(ii) The owner or operator has a written plan that requires
inspection of the equipment as frequently as practicable during safe-
to-inspect times.
(6) Any parts of the closed-vent system or cover that are
designated, as described in paragraphs (c)(6) (i) and (ii) of this
section, as difficult to inspect are exempt from the inspection
requirements of paragraphs (c)(2) (i) and (ii) of this section if:
(i) The owner or operator determines that the equipment cannot be
inspected without elevating the inspecting personnel more than 2 meters
above a support surface; and
(ii) The owner or operator has a written plan that requires
inspection of the equipment at least once every 5 years.
(7) Records shall be maintained as specified in Sec. 63.1284(b)(5)
through (8).
(d) Control device monitoring requirements. (1) For each control
device except as provided for in paragraph (d)(2) of this section, the
owner or operator shall install and operate a continuous parameter
monitoring system in accordance with the requirements of paragraphs
(d)(3) through (9) of this section that will allow a determination to
be made whether the control device is achieving the applicable
performance requirements of Sec. 63.1281(d) or (e)(3). The continuous
parameter monitoring system must meet the following specifications and
requirements:
(i) Each continuous parameter monitoring system shall measure data
values at least once every hour and record either:
(A) Each measured data value; or
(B) Each block average value for each 1-hour period or shorter
periods calculated from all measured data values during each period. If
values are measured more frequently than once per minute, a single
value for each minute may be used to calculate the hourly (or shorter
period) block average instead of all measured values.
(ii) The monitoring system must be installed, calibrated, operated,
and maintained in accordance with the manufacturer's specifications or
other written procedures that provide reasonable assurance that the
monitoring equipment is operating properly.
(2) An owner or operator is exempted from the monitoring
requirements specified in paragraphs (d)(3) through (9) of this section
for the following types of control devices:
[[Page 32658]]
(i) A boiler or process heater in which all vent streams are
introduced with the primary fuel or are used as the primary fuel;
(ii) A boiler or process heater with a design heat input capacity
equal to or greater than 44 megawatts.
(3) The owner or operator shall install, calibrate, operate, and
maintain a device equipped with a continuous recorder to measure the
values of operating parameters appropriate for the control device as
specified in either paragraph (d)(3)(i), (d)(3)(ii), or (d)(3)(iii) of
this section.
(i) A continuous monitoring system that measures the following
operating parameters as applicable:
(A) For a thermal vapor incinerator, a temperature monitoring
device equipped with a continuous recorder. The monitoring device shall
have a minimum accuracy of 2 percent of the temperature
being monitored in deg.C, or 2.5 deg.C, whichever value
is greater. The temperature sensor shall be installed at a location in
the combustion chamber downstream of the combustion zone.
(B) For a catalytic vapor incinerator, a temperature monitoring
device equipped with a continuous recorder. The device shall be capable
of monitoring temperatures at two locations and have a minimum accuracy
of 2 percent of the temperatures being monitored in deg.C,
or 2.5 deg.C, whichever value is greater. One temperature
sensor shall be installed in the vent stream at the nearest feasible
point to the catalyst bed inlet and a second temperature sensor shall
be installed in the vent stream at the nearest feasible point to the
catalyst bed outlet.
(C) For a flare, a heat sensing monitoring device equipped with a
continuous recorder that indicates the continuous ignition of the pilot
flame.
(D) For a boiler or process heater with a design heat input
capacity of less than 44 megawatts, a temperature monitoring device
equipped with a continuous recorder. The temperature monitoring device
shall have a minimum accuracy of 2 percent of the
temperature being monitored in deg.C, or 2.5 deg.C,
whichever value is greater. The temperature sensor shall be installed
at a location in the combustion chamber downstream of the combustion
zone.
(E) For a condenser, a temperature monitoring device equipped with
a continuous recorder. The temperature monitoring device shall have a
minimum accuracy of 2 percent of the temperature being
monitored in deg.C, or 2.5 deg.C, whichever value is
greater. The temperature sensor shall be installed at a location in the
exhaust vent stream from the condenser.
(F) For a regenerative-type carbon adsorption system:
(1) A continuous parameter monitoring system to measure and record
the average total regeneration stream mass flow or volumetric flow
during each carbon bed regeneration cycle. The integrating regenerating
stream flow monitoring device must have an accuracy of 10
percent; and
(2) A continuous parameter monitoring system to measure and record
the average carbon bed temperature for the duration of the carbon bed
steaming cycle and to measure the actual carbon bed temperature after
regeneration and within 15 minutes of completing the cooling cycle. The
temperature monitoring device shall have a minimum accuracy of
2 percent of the temperature being monitored in deg.C, or
2.5 deg.C, whichever value is greater.
(G) For a nonregenerative-type carbon adsorption system, the owner
or operator shall monitor the design carbon replacement interval
established using a performance test performed in accordance with
Sec. 63.1282(d)(3) or a design analysis in accordance with
Sec. 63.1282(d)(4)(i)(F) and shall be based on the total carbon working
capacity of the control device and source operating schedule.
(ii) A continuous monitoring system that measures the concentration
level of organic compounds in the exhaust vent stream from the control
device using an organic monitoring device equipped with a continuous
recorder. The monitor must meet the requirements of Performance
Specification 8 or 9 of appendix B of 40 CFR part 60 and must be
installed, calibrated, and maintained according to the manufacturer's
specifications.
(iii) A continuous monitoring system that measures alternative
operating parameters other than those specified in paragraph (d)(3)(i)
or (d)(3)(ii) of this section upon approval of the Administrator as
specified in Sec. 63.8(f)(1) through (5).
(4) Using the data recorded by the monitoring system, the owner or
operator must calculate the daily average value for each monitored
operating parameter for each operating day. If HAP emissions unit
operation is continuous, the operating day is a 24-hour period. If the
HAP emissions unit operation is not continuous, the operating day is
the total number of hours of control device operation per 24-hour
period. Valid data points must be available for 75 percent of the
operating hours in an operating day to compute the daily average.
(5) For each operating parameter monitored in accordance with the
requirements of paragraph (d)(3) of this section, the owner or operator
shall comply with paragraph (d)(5)(i) of this section for all control
devices, and when condensers are installed, the owner or operator shall
also comply with paragraph (d)(5)(ii) of this section for condensers.
(i) The owner or operator shall establish a minimum operating
parameter value or a maximum operating parameter value, as appropriate
for the control device, to define the conditions at which the control
device must be operated to continuously achieve the applicable
performance requirements of Sec. 63.1281(d)(1) or (e)(3)(ii). Each
minimum or maximum operating parameter value shall be established as
follows:
(A) If the owner or operator conducts performance tests in
accordance with the requirements of Sec. 63.1282(d)(3) to demonstrate
that the control device achieves the applicable performance
requirements specified in Sec. 63.1281(d)(1) or (e)(3)(ii), then the
minimum operating parameter value or the maximum operating parameter
value shall be established based on values measured during the
performance test and supplemented, as necessary, by control device
design analysis or control device manufacturer's recommendations or a
combination of both.
(B) If the owner or operator uses a control device design analysis
in accordance with the requirements of Sec. 63.1282(d)(4) to
demonstrate that the control device achieves the applicable performance
requirements specified in Sec. 63.1281(d)(1) or (e)(3)(ii), then the
minimum operating parameter value or the maximum operating parameter
value shall be established based on the control device design analysis
and may be supplemented by the control device manufacturer's
recommendations.
(ii) The owner or operator shall establish a condenser performance
curve showing the relationship between condenser outlet temperature and
condenser control efficiency. The curve shall be established as
follows:
(A) If the owner or operator conducts a performance test in
accordance with the requirements of Sec. 63.1282(d)(3) to demonstrate
that the condenser achieves the applicable performance requirements in
Sec. 63.1281(d)(1) or (e)(3)(ii), then the condenser performance curve
shall be based on values measured during the performance test and
supplemented as necessary by control device design analysis, or control
device
[[Page 32659]]
manufacturer's recommendations, or a combination or both.
(B) If the owner or operator uses a control device design analysis
in accordance with the requirements of Sec. 63.1282(d)(4)(i)(D) to
demonstrate that the condenser achieves the applicable performance
requirements specified in Sec. 63.1281(d)(1) or (e)(3)(ii), then the
condenser performance curve shall be based on the condenser design
analysis and may be supplemented by the control device manufacturer's
recommendations.
(C) As an alternative to paragraphs (d)(5)(ii)(A) and (B) of this
section, the owner or operator may elect to use the procedures
documented in the GRI report entitled, ``Atmospheric Rich/Lean Method
for Determining Glycol Dehydrator Emissions'' (GRI-95/0368.1) as inputs
for the model GRI-GLYCalcTM, Version 3.0 or higher, to
generate a condenser performance curve.
(6) An excursion for a given control device is determined to have
occurred when the monitoring data or lack of monitoring data result in
any one of the criteria specified in paragraphs (d)(6)(i) through
(d)(6)(iv) of this section being met. When multiple operating
parameters are monitored for the same control device and during the
same operating day, and more than one of these operating parameters
meets an excursion criterion specified in paragraphs (d)(6)(i) through
(d)(6)(iv) of this section, then a single excursion is determined to
have occurred for the control device for that operating day.
(i) An excursion occurs when the daily average value of a monitored
operating parameter is less than the minimum operating parameter limit
(or, if applicable, greater than the maximum operating parameter limit)
established for the operating parameter in accordance with the
requirements of paragraph (d)(5)(i) of this section.
(ii) An excursion occurs when average condenser efficiency
calculated according to the requirements specified in
Sec. 63.1282(f)(2)(iii) is less than 95.0 percent, as specified in
Sec. 63.1282(f)(3).
(iii) An excursion occurs when the monitoring data are not
available for at least 75 percent of the operating hours.
(iv) If the closed-vent system contains one or more bypass devices
that could be used to divert all or a portion of the gases, vapors, or
fumes from entering the control device, an excursion occurs when:
(A) For each bypass line subject to Sec. 63.1281(c)(3)(i)(A) the
flow indicator indicates that flow has been detected and that the
stream has been diverted away from the control device to the
atmosphere.
(B) For each bypass line subject to Sec. 63.1281(c)(3)(i)(B), if
the seal or closure mechanism has been broken, the bypass line valve
position has changed, the key for the lock-and-key type lock has been
checked out, or the car-seal has broken.
(7) For each excursion, except as provided for in paragraph (d)(8)
of this section, the owner or operator shall be deemed to have failed
to have applied control in a manner that achieves the required
operating parameter limits. Failure to achieve the required operating
parameter limits is a violation of this standard.
(8) An excursion is not a violation of the operating parameter
limit as specified in paragraphs (d)(8)(i) and (d)(8)(ii) of this
section.
(i) An excursion does not count toward the number of excused
excursions allowed under paragraph (d)(8)(ii) of this section when the
excursion occurs during any one of the following periods:
(A) During a period of startup, shutdown, or malfunction when the
affected facility is operated during such period in accordance with the
facility's startup, shutdown, and malfunction plan; or
(B) During periods of non-operation of the unit or the process that
is vented to the control device (resulting in cessation of HAP
emissions to which the monitoring applies).
(ii) For each control device, or combinations of control devices,
installed on the same HAP emissions unit, one excused excursion is
allowed per semiannual period for any reason. The initial semiannual
period is the 6-month reporting period addressed by the first Periodic
Report submitted by the owner or operator in accordance with
Sec. 63.1285(e) of this subpart.
(9) Nothing in paragraphs (d)(1) through (d)(8) of this section
shall be construed to allow or excuse a monitoring parameter excursion
caused by any activity that violates other applicable provisions of
this subpart.
Sec. 63.1284 Recordkeeping requirements.
(a) The recordkeeping provisions of subpart A of this part, that
apply and those that do not apply to owners and operators of facilities
subject to this subpart are listed in Table 2 of this subpart.
(b) Except as specified in paragraphs (c) and (d) of this section,
each owner or operator of a facility subject to this subpart shall
maintain the records specified in paragraphs (b)(1) through (b)(10) of
this section:
(1) The owner or operator of an affected source subject to the
provisions of this subpart shall maintain files of all information
(including all reports and notifications) required by this subpart. The
files shall be retained for at least 5 years following the date of each
occurrence, measurement, maintenance, corrective action, report or
period.
(i) All applicable records shall be maintained in such a manner
that they can be readily accessed.
(ii) The most recent 12 months of records shall be retained on site
or shall be accessible from a central location by computer or other
means that provides access within 2 hours after a request.
(iii) The remaining 4 years of records may be retained offsite.
(iv) Records may be maintained in hard copy or computer-readable
form including, but not limited to, on paper, microfilm, computer,
floppy disk, magnetic tape, or microfiche.
(2) Records specified in Sec. 63.10(b)(2);
(3) Records specified in Sec. 63.10(c) for each monitoring system
operated by the owner or operator in accordance with the requirements
of Sec. 63.1283(d). Notwithstanding the previous sentence, monitoring
data recorded during periods identified in paragraphs (b)(2)(i) through
(b)(2)(iv) of this section shall not be included in any average or
percent leak rate computed under this subpart. Records shall be kept of
the times and durations of all such periods and any other periods
during process or control device operation when monitors are not
operating.
(i) Monitoring system breakdowns, repairs, calibration checks, and
zero (low-level) and high-level adjustments;
(ii) Startup, shutdown, and malfunction events. During startup,
shutdown and malfunction events, the owner or operator shall maintain
records indicating whether or not the startup, shutdown, or malfunction
plan, required under Sec. 63.1272(d), was followed.
(iii) Periods of non-operation resulting in cessation of the
emissions to which the monitoring applies; and
(iv) Excursions due to invalid data as defined in
Sec. 63.1283(d)(6)(iii).
(4) Each owner or operator using a control device to comply with
Sec. 63.1274 shall keep the following records up-to-date and readily
accessible:
(i) Continuous records of the equipment operating parameters
specified to be monitored under Sec. 63.1283(d) or specified by the
Administrator in accordance with Sec. 63.1283(d)(3)(iii). For flares,
the hourly records and records of pilot flame outages specified in
Sec. 63.1283(d)(3)(i)(C) shall be maintained in place of continuous
records.
[[Page 32660]]
(ii) Records of the daily average value of each continuously
monitored parameter for each operating day determined according to the
procedures specified in Sec. 63.1283(d)(4) of this subpart. For flares,
records of the times and duration of all periods during which all pilot
flames are absent shall be kept rather than daily averages.
(iii) Hourly records of whether the flow indicator specified under
Sec. 63.1281(c)(3)(i)(A) was operating and whether flow was detected at
any time during the hour, as well as records of the times and durations
of all periods when the vent stream is diverted from the control device
or the monitor is not operating.
(iv) Where a seal or closure mechanism is used to comply with
Sec. 63.1281(c)(3)(i)(B), hourly records of flow are not required. In
such cases, the owner or operator shall record that the monthly visual
inspection of the seals or closure mechanism has been done, and shall
record the duration of all periods when the seal mechanism is broken,
the bypass line valve position has changed, or the key for a lock-and-
key type lock has been checked out, and records of any car-seal that
has broken.
(5) Records identifying all parts of the closed-vent system that
are designated as unsafe to inspect in accordance with
Sec. 63.1283(c)(5), an explanation of why the equipment is unsafe to
inspect, and the plan for inspecting the equipment.
(6) Records identifying all parts of the closed-vent system that
are designated as difficult to inspect in accordance with
Sec. 63.1283(c)(6), an explanation of why the equipment is difficult to
inspect, and the plan for inspecting the equipment.
(7) For each inspection conducted in accordance with
Sec. 63.1283(c), during which a leak or defect is detected, a record of
the information specified in paragraphs (b)(7)(i) through (b)(7)(viii)
of this section.
(i) The instrument identification numbers, operator name or
initials, and identification of the equipment.
(ii) The date the leak or defect was detected and the date of the
first attempt to repair the leak or defect.
(iii) Maximum instrument reading measured by the method specified
in Sec. 63.1283(c)(3) after the leak or defect is successfully repaired
or determined to be nonrepairable.
(iv) ``Repair delayed'' and the reason for the delay if a leak or
defect is not repaired within 15 calendar days after discovery of the
leak or defect.
(v) The name, initials, or other form of identification of the
owner or operator (or designee) whose decision it was that repair could
not be effected without a shutdown.
(vi) The expected date of successful repair of the leak or defect
if a leak or defect is not repaired within 15 calendar days.
(vii) Dates of shutdowns that occur while the equipment is
unrepaired.
(viii) The date of successful repair of the leak or defect.
(8) For each inspection conducted in accordance with
Sec. 63.1283(c) during which no leaks or defects are detected, a record
that the inspection was performed, the date of the inspection, and a
statement that no leaks or defects were detected.
(9) Records of glycol dehydration unit baseline operations
calculated as required under Sec. 63.1281(e)(1).
(10) Records required in Sec. 63.1281(e)(3)(i) documenting that the
facility continues to operate under the conditions specified in
Sec. 63.1281(e)(2).
(c) An owner or operator that elects to comply with the benzene
emission limit specified in Sec. 63.1275(b)(1)(ii) shall document, to
the Administrator's satisfaction, the following items:
(1) The method used for achieving compliance and the basis for
using this compliance method; and
(2) The method used for demonstrating compliance with 0.90
megagrams per year of benzene.
(3) Any information necessary to demonstrate compliance as required
in the methods specified in paragraphs (c)(1) and (c)(2) of this
section.
(d) An owner or operator that is exempt from control requirements
under Sec. 63.1274(d) shall maintain the records specified in paragraph
(d)(1) or (d)(2) of this section, as appropriate, for each glycol
dehydration unit that is not controlled according to the requirements
of Sec. 63.1274(c).
(1) The actual annual average natural gas throughput (in terms of
natural gas flowrate to the glycol dehydration unit per day), as
determined in accordance with Sec. 63.1282(a)(1); or
(2) The actual average benzene emissions (in terms of benzene
emissions per year), as determined in accordance with
Sec. 63.1282(a)(2).
(e) Record the following when using a flare to comply with
Sec. 63.1281(d):
(1) Flare design (i.e., steam-assisted, air-assisted, or non-
assisted);
(2) All visible emission readings, heat content determinations,
flowrate measurements, and exit velocity determinations made during the
compliance determination required by Sec. 63.1282(d)(2); and
(3) All periods during the compliance determination when the pilot
flame is absent.
Sec. 63.1285 Reporting requirements.
(a) The reporting provisions of subpart A, of this part that apply
and those that do not apply to owners and operators of facilities
subject to this subpart are listed in Table 2 of this subpart.
(b) Each owner or operator of a facility subject to this subpart
shall submit the information listed in paragraphs (b)(1) through (b)(6)
of this section, except as provided in paragraph (b)(7) of this
section.
(1) The initial notifications required for existing affected
sources under Sec. 63.9(b)(2) shall be submitted by 1 year after an
affected source becomes subject to the provisions of this subpart or by
June 17, 2000, whichever is later. Affected sources that are major
sources on or before June 17, 2000 and plan to be area sources by June
17, 2002 shall include in this notification a brief, nonbinding
description of a schedule for the action(s) that are planned to achieve
area source status.
(2) The date of the performance evaluation as specified in
Sec. 63.8(e)(2), required only if the owner or operator is requested by
the Administrator to conduct a performance evaluation for a continuous
monitoring system. A separate notification of the performance
evaluation is not required if it is included in the initial
notification submitted in accordance with paragraph (b)(1) of this
section.
(3) The planned date of a performance test at least 60 days before
the test in accordance with Sec. 63.7(b). Unless requested by the
Administrator, a site-specific test plan is not required by this
subpart. If requested by the Administrator, the owner or operator must
also submit the site-specific test plan required by Sec. 63.7(c) with
the notification of the performance test. A separate notification of
the performance test is not required if it is included in the initial
notification submitted in accordance with paragraph (b)(1) of this
section.
(4) A Notification of Compliance Status Report as described in
paragraph (d) of this section;
(5) Periodic Reports as described in paragraph (e) of this section;
and
(6) Startup, shutdown, and malfunction reports, as specified in
Sec. 63.10(d)(5), shall be submitted as required. Separate startup,
shutdown, or malfunction reports as described in Sec. 63.10(d)(5)(i)
are not required if the information is included in the Periodic Report
specified in paragraph (e) of this section.
(7) Each owner or operator of a glycol dehydration unit subject to
this subpart that is exempt from the control
[[Page 32661]]
requirements for glycol dehydration unit process vents in Sec. 63.1275,
is exempt from all reporting requirements for major sources in this
subpart for that unit.
(c) [Reserved]
(d) Each owner or operator of a source subject to this subpart
shall submit a Notification of Compliance Status Report as required
under Sec. 63.9(h) within 180 days after the compliance date specified
in Sec. 63.1270(d). In addition to the information required under
Sec. 63.9(h), the Notification of Compliance Status Report shall
include the information specified in paragraphs (d)(1) through (d)(10)
of this section. This information may be submitted in an operating
permit application, in an amendment to an operating permit application,
in a separate submittal, or in any combination of the three. If all of
the information required under this paragraph have been submitted at
any time prior to 180 days after the applicable compliance dates
specified in Sec. 63.1270(d), a separate Notification of Compliance
Status Report is not required. If an owner or operator submits the
information specified in paragraphs (d)(1) through (d)(9) of this
section at different times, and/or different submittals, later
submittals may refer to earlier submittals instead of duplicating and
resubmitting the previously submitted information.
(1) If a closed-vent system and a control device other than a flare
are used to comply with Sec. 63.1274, the owner or operator shall
submit:
(i) The design analysis documentation specified in
Sec. 63.1282(d)(4) of this subpart if the owner or operator elects to
prepare a design analysis; or
(ii) If the owner or operator elects to conduct a performance test,
the performance test results including the information specified in
paragraphs (d)(1)(ii)(A) and (B) of this section. Results of a
performance test conducted prior to the compliance date of this subpart
can be used provided that the test was conducted using the methods
specified in Sec. 63.1282(d)(3), and that the test conditions are
representative of current operating conditions.
(A) The percent reduction of HAP or TOC, or the outlet
concentration of HAP or TOC (parts per million by volume on a dry
basis), determined as specified in Sec. 63.1282(d)(3) of this subpart;
and
(B) The value of the monitored parameters specified in
Sec. 63.1283(d) of this subpart, or a site-specific parameter approved
by the permitting agency, averaged over the full period of the
performance test.
(2) If a closed-vent system and a flare are used to comply with
Sec. 63.1274, the owner or operator shall submit performance test
results including the information in paragraphs (d)(2)(i) and (ii) of
this section.
(i) All visible emission readings, heat content determinations,
flowrate measurements, and exit velocity determinations made during the
compliance determination required by Sec. 63.1282(d)(2) of this
subpart, and
(ii) A statement of whether a flame was present at the pilot light
over the full period of the compliance determination.
(3) The owner or operator shall submit one complete test report for
each test method used for a particular source.
(i) For additional tests performed using the same test method, the
results specified in paragraph (d)(1)(ii) of this section shall be
submitted, but a complete test report is not required.
(ii) A complete test report shall include a sampling site
description, description of sampling and analysis procedures and any
modifications to standard procedures, quality assurance procedures,
record of operating conditions during the test, record of preparation
of standards, record of calibrations, raw data sheets for field
sampling, raw data sheets for field and laboratory analyses,
documentation of calculations, and any other information required by
the test method.
(4) For each control device other than a flare used to meet the
requirements of Sec. 63.1274, the owner or operator shall submit the
information specified in paragraphs (d)(4)(i) through (iii) of this
section for each operating parameter required to be monitored in
accordance with the requirements of Sec. 63.1283(d).
(i) The minimum operating parameter value or maximum operating
parameter value, as appropriate for the control device, established by
the owner or operator to define the conditions at which the control
device must be operated to continuously achieve the applicable
performance requirements of Sec. 63.1281(d)(1) or (e)(3)(ii).
(ii) An explanation of the rationale for why the owner or operator
selected each of the operating parameter values established in
Sec. 63.1283(d)(5) of this subpart. This explanation shall include any
data and calculations used to develop the value, and a description of
why the chosen value indicates that the control device is operating in
accordance with the applicable requirements of Sec. 63.1281(d)(1) or
(e)(3)(ii).
(iii) A definition of the source's operating day for purposes of
determining daily average values of monitored parameters. The
definition shall specify the times at which an operating day begins and
ends.
(5) Results of any continuous monitoring system performance
evaluations shall be included in the Notification of Compliance Status
Report.
(6) After a title V permit has been issued to the owner or operator
of an affected source, the owner or operator of such source shall
comply with all requirements for compliance status reports contained in
the source's title V permit, including reports required under this
subpart. After a title V permit has been issued to the owner or
operator of an affected source, and each time a notification of
compliance status is required under this subpart, the owner or operator
of such source shall submit the notification of compliance status to
the appropriate permitting authority following completion of the
relevant compliance demonstration activity specified in this subpart.
(7) The owner or operator that elects to comply with the
requirements of Sec. 63.1275(b)(1)(ii) shall submit the records
required under Sec. 63.1284(c).
(8) The owner or operator shall submit an analysis demonstrating
whether an affected source is a major source using the maximum
throughput calculated according to Sec. 63.1270(a).
(9) The owner or operator shall submit a statement as to whether
the source has complied with the requirements of this subpart.
(10) The owner or operator shall submit the analysis prepared under
Sec. 63.1281(e)(2) to demonstrate that the conditions by which the
facility will be operated to achieve an overall HAP emission reduction
of 95.0 percent through process modifications or a combination of
process modifications and one or more control devices.
(e) Periodic Reports. An owner or operator shall prepare Periodic
Reports in accordance with paragraphs (e)(1) and (2) of this section
and submit them to the Administrator.
(1) An owner or operator shall submit Periodic Reports
semiannually, beginning 60 operating days after the end of the
applicable reporting period. The first report shall be submitted no
later than 240 days after the date the Notification of Compliance
Status Report is due and shall cover the 6-month period beginning on
the date the Notification of Compliance Status Report is due.
(2) The owner or operator shall include the information specified
in paragraphs (e)(2)(i) through (viii) of this section, as applicable.
(i) The information required under Sec. 63.10(e)(3). For the
purposes of this
[[Page 32662]]
subpart and the information required under Sec. 63.10(e)(3), excursions
(as defined in Sec. 63.1283(d)(6)) shall be considered excess
emissions.
(ii) A description of all excursions as defined in
Sec. 63.1283(d)(6) of this subpart that have occurred during the 6-
month reporting period.
(A) For each excursion caused when the daily average value of a
monitored operating parameter is less than the minimum operating
parameter limit (or, if applicable, greater than the maximum operating
parameter limit), as specified in Sec. 63.1283(d)(6)(i), the report
must include the daily average values of the monitored parameter, the
applicable operating parameter limit, and the date and duration of the
period that the excursion occurred.
(B) For each excursion caused when the 30-day average condenser
control efficiency is less than 95.0 percent, as specified in
Sec. 63.1283(d)(6)(ii), the report must include the 30-day average
values of the condenser control efficiency, and the date and duration
of the period that the excursion occurred.
(C) For each excursion caused by lack of monitoring data, as
specified in Sec. 63.1283(d)(6)(iii), the report must include the date
and duration of period when the monitoring data were not collected and
the reason why the data were not collected.
(iii) For each inspection conducted in accordance with
Sec. 63.1283(c) during which a leak or defect is detected, the records
specified in Sec. 63.1284(b)(7) must be included in the next Periodic
Report.
(iv) For each closed-vent system with a bypass line subject to
Sec. 63.1281(c)(3)(i)(A), records required under
Sec. 63.1284(b)(4)(iii) of all periods when the vent stream is diverted
from the control device through a bypass line. For each closed-vent
system with a bypass line subject to Sec. 63.1281(c)(3)(i)(B), records
required under Sec. 63.1284(b)(4)(iv) of all periods in which the seal
or closure mechanism is broken, the bypass valve position has changed,
or the key to unlock the bypass line valve was checked out.
(v) If an owner or operator elects to comply with
Sec. 63.1275(b)(1)(ii), the records required under Sec. 63.1284(c)(3).
(vi) The information in paragraphs (e)(2)(vi)(A) and (B) of this
section shall be stated in the Periodic Report, when applicable.
(A) No excursions.
(B) No continuous monitoring system has been inoperative, out of
control, repaired, or adjusted.
(vii) Any change in compliance methods as specified in
Sec. 63.1275(b).
(viii) If the owner or operator elects to comply with
Sec. 63.1275(c)(2), the records required under Sec. 63.1284(b)(10).
(f) Notification of process change. Whenever a process change is
made, or a change in any of the information submitted in the
Notification of Compliance Status Report, the owner or operator shall
submit a report within 180 days after the process change is made or as
a part of the next Periodic Report as required under paragraph (e) of
this section, whichever is sooner. The report shall include:
(1) A brief description of the process change;
(2) A description of any modification to standard procedures or
quality assurance procedures;
(3) Revisions to any of the information reported in the original
Notification of Compliance Status Report under paragraph (d) of this
section; and
(4) Information required by the Notification of Compliance Status
Report under paragraph (d) of this section for changes involving the
addition of processes or equipment.
Sec. 63.1286 Delegation of authority.
(a) In delegating implementation and enforcement authority to a
State under section 112(l) of the Act, the authorities contained in
paragraph (b) of this section shall be retained by the Administrator
and not transferred to a State.
(b) Authorities will not be delegated to States for Secs. 63.1282
and 63.1287 of this subpart.
Sec. 63.1287 Alternative means of emission limitation.
(a) If, in the judgment of the Administrator, an alternative means
of emission limitation will achieve a reduction in HAP emissions at
least equivalent to the reduction in HAP emissions from that source
achieved under the applicable requirements in Secs. 63.1274 through
63.1281, the Administrator will publish a notice in the Federal
Register permitting the use of the alternative means for purposes of
compliance with that requirement. The notice may condition the
permission on requirements related to the operation and maintenance of
the alternative means.
(b) Any notice under paragraph (a) of this section shall be
published only after public notice and an opportunity for a hearing.
(c) Any person seeking permission to use an alternative means of
compliance under this section shall collect, verify, and submit to the
Administrator information showing that this means achieves equivalent
emission reductions.
Sec. 63.1288 [Reserved]
Sec. 63.1289 [Reserved]
Appendix to Subpart HHH--Tables
Table 1.--List of Hazardous Air Pollutants (HAP) for Subpart HHH
------------------------------------------------------------------------
CAS Number a Chemical name
------------------------------------------------------------------------
75070.................................. Acetaldehyde
71432.................................. Benzene (includes benzene in
gasoline)
75150.................................. Carbon disulfide
463581................................. Carbonyl sulfide
100414................................. Ethyl benzene
107211................................. Ethylene glycol
75050.................................. Acetaldehyde
50000.................................. Formaldehyde
110543................................. n-Hexane
91203.................................. Naphthalene
108883................................. Toluene
540841................................. 2,2,4-Trimethylpentane
1330207................................ Xylenes (isomers and mixture)
95476.................................. o-Xylene
108383................................. m-Xylene
106423................................. p-Xylene
------------------------------------------------------------------------
a CAS numbers refer to the Chemical Abstracts Services registry number
assigned to specific compounds, isomers, or mixtures of compounds.
Table 2 to Subpart HHH.--Applicability of 40 CFR Part 63 General Provisions to Subpart HHH
----------------------------------------------------------------------------------------------------------------
General provisions reference Applicable to subpart HHH Explanation
----------------------------------------------------------------------------------------------------------------
Sec. 63.1(a)(1)................... Yes
Sec. 63.1(a)(2)................... Yes
Sec. 63.1(a)(3)................... Yes
Sec. 63.1(a)(4)................... Yes
Sec. 63.1(a)(5)................... No......................... Section reserved.
Sec. 63.1(a)(6) through (a)(8).... Yes
Sec. 63.1(a)(9)................... No......................... Section reserved.
Sec. 63.1(a)(10).................. Yes
[[Page 32663]]
Sec. 63.1(a)(11).................. Yes
Sec. 63.1(a)(12) through (a)(14).. Yes
Sec. 63.1(b)(1)................... No......................... Subpart HHH specifies applicability.
Sec. 63.1(b)(2)................... Yes
Sec. 63.1(b)(3)................... No.........................
Sec. 63.1(c)(1)................... No......................... Subpart HHH specifies applicability.
Sec. 63.1(c)(2)................... No
Sec. 63.1(c)(3)................... No......................... Section reserved.
Sec. 63.1(c)(4)................... Yes
Sec. 63.1(c)(5)................... Yes
Sec. 63.1(d)...................... No......................... Section reserved.
Sec. 63.1(e)...................... Yes
Sec. 63.2......................... Yes........................ Except definition of major source is unique
for this source category and there are
additional definitions in subpart HHH.
Sec. 63.3(a) through (c).......... Yes
Sec. 63.4(a)(1) through (a)(3).... Yes
Sec. 63.4(a)(4)................... No......................... Section reserved.
Sec. 63.4(a)(5)................... Yes
Sec. 63.4(b)...................... Yes
Sec. 63.4(c)...................... Yes
Sec. 63.5(a)(1)................... Yes
Sec. 63.5(a)(2)................... No......................... Preconstruction review required only for major
sources that commence construction after
promulgation of the standard.
Sec. 63.5(b)(1)................... Yes
Sec. 63.5(b)(2)................... No......................... Section reserved.
Sec. 63.5(b)(3)................... Yes
Sec. 63.5(b)(4)................... Yes
Sec. 63.5(b)(5)................... Yes
Sec. 63.5(b)(6)................... Yes
Sec. 63.5(c)...................... No......................... Section reserved.
Sec. 63.5(d)(1)................... Yes
Sec. 63.5(d)(2)................... Yes
Sec. 63.5(d)(3)................... Yes
Sec. 63.5(d)(4)................... Yes
Sec. 63.5(e)...................... Yes
Sec. 63.5(f)(1)................... Yes
Sec. 63.5(f)(2)................... Yes
Sec. 63.6(a)...................... Yes
Sec. 63.6(b)(1)................... Yes
Sec. 63.6(b)(2)................... Yes
Sec. 63.6(b)(3)................... Yes
Sec. 63.6(b)(4)................... Yes
Sec. 63.6(b)(5)................... Yes
Sec. 63.6(b)(6)................... No......................... Section reserved.
Sec. 63.6(b)(7)................... Yes
Sec. 63.6(c)(1)................... Yes
Sec. 63.6(c)(2)................... Yes
Sec. 63.6(c)(3) and (c)(4)........ No......................... Section reserved.
Sec. 63.6(c)(5)................... Yes
Sec. 63.6(d)...................... No......................... Section reserved.
Sec. 63.6(e)...................... Yes
Sec. 63.6(e)...................... Yes Except as otherwise specified.
Sec. 63.6(e)(1)(i)................ No......................... Addressed in Sec. 63.1272.
Sec. 63.6(e)(1)(ii)............... Yes
Sec. 63.6(e)(1)(iii).............. Yes
Sec. 63.6(e)(2)................... Yes
Sec. 63.6(e)(3)(i)................ Yes........................ Except as otherwise specified.
Sec. 63.6(e)(3)(i)(A)............. No......................... Addressed by Sec. 63.1272(c).
Sec. 63.6(e)(3)(i)(B)............. Yes
Sec. 63.6(e)(3)(i)(C)............. Yes
Sec. 63.6(e)(3)(ii) through Yes
(3)(vi).
Sec. 63.6(e)(3)(vii)..............
Sec. 63.6(e)(3)(vii) (A).......... Yes
Sec. 63.6(e)(3)(vii) (B).......... Yes........................ Except that the plan must provide for
operation in compliance with Sec.
63.1272(c).
Sec. 63.6(e)(3)(vii) (C).......... Yes
Sec. 63.6(e)3)(viii).............. Yes
Sec. 63.7(e)(1)................... Yes
Sec. 63.7(e)(2)................... Yes
Sec. 63.7(e)(3)................... Yes
Sec. 63.7(e)(4)................... Yes
Sec. 63.7(f)...................... Yes
Sec. 63.7(g)...................... Yes
Sec. 63.7(h)...................... Yes
Sec. 63.8(a)(1)................... Yes
Sec. 63.8(a)(2)................... Yes
Sec. 63.8(a)(3)................... No......................... Section reserved.
Sec. 63.8(a)(4)................... Yes
Sec. 63.8(b)(1)................... Yes
Sec. 63.8(b)(2)................... Yes
Sec. 63.8(b)(3)................... Yes
[[Page 32664]]
Sec. 63.8(c)(1)................... Yes
Sec. 63.8(c)(2)................... Yes
Sec. 63.8(c)(3)................... Yes
Sec. 63.8(c)(4)................... No.........................
Sec. 63.8(c)(5) through (c)(8).... Yes
Sec. 63.8(d)...................... Yes
Sec. 63.8(e)...................... Yes........................ Subpart HHH does not specifically require
continuous emissions monitor performance
evaluations, however, the Administrator can
request that one be conducted.
Sec. 63.8(f)(1) through (f)(5).... Yes
Sec. 63.8(f)(6)................... No......................... Subpart HHH does not require continuous
emissions monitoring.
Sec. 63.8(g)...................... No......................... Subpart HHH specifies continuous monitoring
system data reduction requirements.
Sec. 63.9(a)...................... Yes
Sec. 63.9(b)(1)................... Yes
Sec. 63.9(b)(2)................... Yes........................ Sources are given 1 year (rather than 120
days) to submit this notification.
Sec. 63.9(b)(3)................... Yes
Sec. 63.9(b)(4)................... Yes
Sec. 63.9(b)(5)................... Yes
Sec. 63.9(c)...................... Yes
Sec. 63.9(d)...................... Yes
Sec. 63.9(e)...................... Yes
Sec. 63.9(f)...................... No.........................
Sec. 63.9(g)...................... Yes
Sec. 63.9(h)(1) through (h)(3).... Yes
Sec. 63.9(h)(4)................... No......................... Section reserved.
Sec. 63.9(h)(5) and (h)(6)........ Yes
Sec. 63.9(i)...................... Yes
Sec. 63.9(j)...................... Yes
Sec. 63.10(a)..................... Yes
Sec. 63.10(b)(1).................. Yes
Sec. 63.10(b)(2).................. Yes
Sec. 63.10(b)(3).................. No
Sec. 63.10(c)(1).................. Yes
Sec. 63.10(c)(2) through (c)(4)... No......................... Sections reserved.
Sec. 63.10(c)(5) through (c)(8)... Yes
Sec. 63.10(c)(9).................. No......................... Section reserved.
Sec. 63.10(c)(10) through (c)(15). Yes
Sec. 63.10(d)(1).................. Yes
Sec. 63.10(d)(2).................. Yes
Sec. 63.10(d)(3).................. Yes
Sec. 63.10(d)(4).................. Yes
Sec. 63.10(d)(5).................. Yes........................ Subpart HHH requires major sources to submit a
startup, shutdown and malfunction report semi-
annually.
Sec. 63.10(e)(1).................. Yes
Sec. 63.10(e)(2).................. Yes
Sec. 63.10(e)(3)(i)............... Yes........................ Subpart HHH requires major sources to submit
Periodic Reports semi-annually.
Sec. 63.10(e)(3)(i)(A)............ Yes
Sec. 63.10(e)(3)(i)(B)............ Yes
Sec. 63.10(e)(3)(i)(C)............ No......................... Subpart HHH does not require quarterly
reporting for excess emissions.
Sec. 63.10(e)(3)(ii) through Yes
(e)(3)(viii).
Sec. 63.10(f)..................... Yes
Sec. 63.11(a) and (b)............. Yes
Sec. 63.12(a) through (c)......... Yes
Sec. 63.13(a) through (c)......... Yes
Sec. 63.14(a) and (b)............. Yes
Sec. 63.15(a) and (b)............. Yes
----------------------------------------------------------------------------------------------------------------
[FR Doc. 99-12894 Filed 6-16-99; 8:45 am]
BILLING CODE 6560-50-P