[Federal Register Volume 76, Number 163 (Tuesday, August 23, 2011)]
[Proposed Rules]
[Pages 52738-52843]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2011-19899]
[[Page 52737]]
Vol. 76
Tuesday,
No. 163
August 23, 2011
Part II
Environmental Protection Agency
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40 CFR Parts 60 and 63
Oil and Natural Gas Sector: New Source Performance Standards and
National Emission Standards for Hazardous Air Pollutants Reviews;
Proposed Rule
Federal Register / Vol. 76 , No. 163 / Tuesday, August 23, 2011 /
Proposed Rules
[[Page 52738]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 60 and 63
[EPA-HQ-OAR-2010-0505; FRL-9448-6]
RIN 2060-AP76
Oil and Natural Gas Sector: New Source Performance Standards and
National Emission Standards for Hazardous Air Pollutants Reviews
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: This action announces how the EPA proposes to address the
reviews of the new source performance standards for volatile organic
compound and sulfur dioxide emissions from natural gas processing
plants. We are proposing to add to the source category list any oil and
gas operation not covered by the current listing. This action also
includes proposed amendments to the existing new source performance
standards for volatile organic compounds from natural gas processing
plants and proposed standards for operations that are not covered by
the existing new source performance standards. In addition, this action
proposes how the EPA will address the residual risk and technology
review conducted for the oil and natural gas production and natural gas
transmission and storage national emission standards for hazardous air
pollutants. This action further proposes standards for emission sources
within these two source categories that are not currently addressed, as
well as amendments to improve aspects of these national emission
standards for hazardous air pollutants related to applicability and
implementation. Finally, this action addresses provisions in these new
source performance standards and national emission standards for
hazardous air pollutants related to emissions during periods of
startup, shutdown and malfunction.
DATES: Comments must be received on or before October 24, 2011.
Public Hearing. Three public hearings will be held to provide the
public an opportunity to provide comments on this proposed rulemaking.
One will be held in the Dallas, Texas area, one in Pittsburgh,
Pennsylvania, and one in Denver, Colorado, on dates to be announced in
a separate document. Each hearing will convene at 10 a.m. local time.
For additional information on the public hearings and requesting to
speak, see the SUPPLEMENTARY INFORMATION section of this preamble.
ADDRESSES: Submit your comments, identified by Docket ID Number EPA-HQ-
OAR-2010-0505, by one of the following methods:
Federal eRulemaking Portal: http://www.regulations.gov:
Follow the instructions for submitting comments.
Agency Web site: http://www.epa.gov/oar/docket.html.
Follow the instructions for submitting comments on the Air and
Radiation Docket Web site.
E-mail: [email protected]. Include Docket ID Number
EPA-HQ-OAR-2010-0505 in the subject line of the message.
Facsimile: (202) 566-9744.
Mail: Attention Docket ID Number EPA-HQ-OAR-2010-0505,
1200 Pennsylvania Ave., NW., Washington, DC 20460. Please include a
total of two copies. In addition, please mail a copy of your comments
on the information collection provisions to the Office of Information
and Regulatory Affairs, Office of Management and Budget (OMB), Attn:
Desk Officer for the EPA, 725 17th Street, NW., Washington, DC 20503.
Hand Delivery: United States Environmental Protection
Agency, EPA West (Air Docket), Room 3334, 1301 Constitution Ave., NW.,
Washington, DC 20004, Attention Docket ID Number EPA-HQ-OAR-2010-0505.
Such deliveries are only accepted during the Docket's normal hours of
operation, and special arrangements should be made for deliveries of
boxed information.
Instructions: Direct your comments to Docket ID Number EPA-HQ-OAR-
2010-0505. The EPA's policy is that all comments received will be
included in the public docket without change and may be made available
online at http://www.regulations.gov, including any personal
information provided, unless the comment includes information claimed
to be confidential business information (CBI) or other information
whose disclosure is restricted by statute. Do not submit information
that you consider to be CBI or otherwise protected through http://www.regulations.gov or e-mail. The http://www.regulations.gov Web site
is an ``anonymous access'' system, which means the EPA will not know
your identity or contact information unless you provide it in the body
of your comment. If you send an e-mail comment directly to the EPA
without going through http://www.regulations.gov, your e-mail address
will be automatically captured and included as part of the comment that
is placed in the public docket and made available on the Internet. If
you submit an electronic comment, the EPA recommends that you include
your name and other contact information in the body of your comment and
with any disk or CD-ROM you submit. If the EPA cannot read your comment
due to technical difficulties and cannot contact you for clarification,
the EPA may not be able to consider your comment. Electronic files
should avoid the use of special characters, any form of encryption, and
be free of any defects or viruses. For additional information about the
EPA's public docket, visit the EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm. For additional instructions on
submitting comments, go to section II.C of the SUPPLEMENTARY
INFORMATION section of this preamble.
Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, is not placed on the Internet and will be
publicly available only in hard copy. Publicly available docket
materials are available either electronically through http://www.regulations.gov or in hard copy at the U.S. Environmental
Protection Agency, EPA West (Air Docket), Room 3334, 1301 Constitution
Ave., NW., Washington, DC 20004. The Public Reading Room is open from
8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal
holidays. The telephone number for the Public Reading Room is (202)
566-1744, and the telephone number for the Air Docket is (202) 566-
1742.
FOR FURTHER INFORMATION CONTACT: Bruce Moore, Sector Policies and
Programs Division, Office of Air Quality Planning and Standards (E143-
01), Environmental Protection Agency, Research Triangle Park, North
Carolina 27711, telephone number: (919) 541-5460; facsimile number:
(919) 685-3200; e-mail address: [email protected].
SUPPLEMENTARY INFORMATION:
Organization of This Document. The following outline is provided to
aid in locating information in this preamble.
I. Preamble Acronyms and Abbreviations
II. General Information
A. Does this action apply to me?
B. Where can I get a copy of this document and other related
information?
C. What should I consider as I prepare my comments for the EPA?
D. When will a public hearing occur?
III. Background Information
A. What are standards of performance and NSPS?
B. What are NESHAP?
[[Page 52739]]
C. What litigation is related to this proposed action?
D. What is a sector-based approach?
IV. Oil and Natural Gas Sector
V. Summary of Proposed Decisions and Actions
A. What are the proposed revisions to the NSPS?
B. What are the proposed decisions and actions related to the
NESHAP?
C. What are the proposed notification, recordkeeping and
reporting requirements for this proposed action?
D. What are the innovative compliance approaches being
considered?
E. How does the NSPS relate to permitting of sources?
VI. Rationale for Proposed Action for NSPS
A. What did we evaluate relative to NSPS?
B. What are the results of our evaluations and proposed actions
relative to NSPS?
VII. Rationale for Proposed Action for NESHAP
A. What data were used for the NESHAP analyses?
B. What are the proposed decisions regarding certain unregulated
emissions sources?
C. How did we perform the risk assessment and what are the
results and proposed decisions?
D. How did we perform the technology review and what are the
results and proposed decisions?
E. What other actions are we proposing?
VIII. What are the cost, environmental, energy and economic impacts
of the proposed 40 CFR part 60, subpart OOOO and amendments to
subparts HH and HHH of 40 CFR part 63?
A. What are the affected sources?
B. How are the impacts for this proposal evaluated?
C. What are the air quality impacts?
D. What are the water quality and solid waste impacts?
E. What are the secondary impacts?
F. What are the energy impacts?
G. What are the cost impacts?
H. What are the economic impacts?
I. What are the benefits?
IX. Request for Comments
X. Submitting Data Corrections
XI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
I. Preamble Acronyms and Abbreviations
Several acronyms and terms used to describe industrial processes,
data inventories and risk modeling are included in this preamble. While
this may not be an exhaustive list, to ease the reading of this
preamble and for reference purposes, the following terms and acronyms
are defined here:
ACGIH American Conference of Governmental Industrial Hygienists
ADAF Age-Dependent Adjustment Factors
AEGL Acute Exposure Guideline Levels
AERMOD The air dispersion model used by the HEM-3 model
API American Petroleum Institute
BACT Best Available Control Technology
BID Background Information Document
BPD Barrels Per Day
BSER Best System of Emission Reduction
BTEX Benzene, Ethylbenzene, Toluene and Xylene
CAA Clean Air Act
CalEPA California Environmental Protection Agency
CBI Confidential Business Information
CEM Continuous Emissions Monitoring
CEMS Continuous Emissions Monitoring System
CFR Code of Federal Regulations
CIIT Chemical Industry Institute of Toxicology
CO Carbon Monoxide
CO2 Carbon Dioxide
CO2e Carbon Dioxide Equivalent
DOE Department of Energy
ECHO Enforcement and Compliance History Online
e-GGRT Electronic Greenhouse Gas Reporting Tool
EJ Environmental Justice
EPA Environmental Protection Agency
ERPG Emergency Response Planning Guidelines
ERT Electronic Reporting Tool
GCG Gas Condensate Glycol
GHG Greenhouse Gas
GOR Gas to Oil Ratio
GWP Global Warming Potential
HAP Hazardous Air Pollutants
HEM-3 Human Exposure Model, version 3
HI Hazard Index
HP Horsepower
HQ Hazard Quotient
H2S Hydrogen Sulfide
ICR Information Collection Request
IPCC Intergovernmental Panel on Climate Change
IRIS Integrated Risk Information System
km Kilometer
kW Kilowatts
LAER Lowest Achievable Emission Rate
lb Pounds
LDAR Leak Detection and Repair
MACT Maximum Achievable Control Technology
MACT Code Code within the NEI used to identify processes included in
a source category
Mcf Thousand Cubic Feet
Mg/yr Megagrams per year
MIR Maximum Individual Risk
MIRR Monitoring, Inspection, Recordkeeping and Reporting
MMtCO2e Million Metric Tons of Carbon Dioxide Equivalents
NAAQS National Ambient Air Quality Standards
NAC/AEGL National Advisory Committee for Acute Exposure Guideline
Levels for Hazardous Substances
NAICS North American Industry Classification System
NAS National Academy of Sciences
NATA National Air Toxics Assessment
NEI National Emissions Inventory
NEMS National Energy Modeling System
NESHAP National Emissions Standards for Hazardous Air Pollutants
NGL Natural Gas Liquids
NIOSH National Institutes for Occupational Safety and Health
NOX Oxides of Nitrogen
NRC National Research Council
NSPS New Source Performance Standards
NSR New Source Review
NTTAA National Technology Transfer and Advancement Act
OAQPS Office of Air Quality Planning and Standards
OMB Office of Management and Budget
PB-HAP Hazardous air pollutants known to be persistent and bio-
accumulative in the environment
PFE Potential for Flash Emissions
PM Particulate Matter
PM2.5 Particulate Matter (2.5 microns and less)
POM Polycyclic Organic Matter
PPM Parts Per Million
PPMV Parts Per Million by Volume
PSIG Pounds per square inch gauge
PTE Potential to Emit
QA Quality Assurance
RACT Reasonably Available Control Technology
RBLC RACT/BACT/LAER Clearinghouse
REC Reduced Emissions Completions
REL CalEPA Reference Exposure Level
RFA Regulatory Flexibility Act
RfC Reference Concentration
RfD Reference Dose
RIA Regulatory Impact Analysis
RICE Reciprocating Internal Combustion Engines
RTR Residual Risk and Technology Review
SAB Science Advisory Board
SBREFA Small Business Regulatory Enforcement Fairness Act
SCC Source Classification Codes
SCFH Standard Cubic Feet Per Hour
SCFM Standard Cubic Feet Per Minute
SCM Standard Cubic Meters
SCMD Standard Cubic Meters Per Day
SCOT Shell Claus Offgas Treatment
SIP State Implementation Plan
SISNOSE Significant Economic Impact on a Substantial Number of Small
Entities
S/L/T State and Local and Tribal Agencies
SO2 Sulfur Dioxide
SSM Startup, Shutdown and Malfunction
STEL Short-term Exposure Limit
TLV Threshold Limit Value
TOSHI Target Organ-Specific Hazard Index
TPY Tons per Year
TRIM Total Risk Integrated Modeling System
TRIM.FaTE A spatially explicit, compartmental mass balance model
that
[[Page 52740]]
describes the movement and transformation of pollutants over time,
through a user-defined, bounded system that includes both biotic and
abiotic compartments
TSD Technical Support Document
UF Uncertainty Factor
UMRA Unfunded Mandates Reform Act
URE Unit Risk Estimate
VCS Voluntary Consensus Standards
VOC Volatile Organic Compounds
VRU Vapor Recovery Unit
II. General Information
A. Does this action apply to me?
The regulated industrial source categories that are the subject of
this proposal are listed in Table 1 of this preamble. These standards
and any changes considered in this rulemaking would be directly
applicable to sources as a Federal program. Thus, Federal, state, local
and tribal government entities are not affected by this proposed
action.
Table 1--Industrial Source Categories Affected by This Proposed Action
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NAICS code Examples of regulated
Category \1\ entities
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Industry........................... 211111 Crude Petroleum and
Natural Gas
Extraction.
211112 Natural Gas Liquid
Extraction.
221210 Natural Gas
Distribution.
486110 Pipeline Distribution
of Crude Oil.
486210 Pipeline
Transportation of
Natural Gas.
Federal government................. ........... Not affected.
State/local/tribal government...... ........... Not affected.
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\1\ North American Industry Classification System.
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be affected by this
action. To determine whether your facility would be regulated by this
action, you should examine the applicability criteria in the
regulations. If you have any questions regarding the applicability of
this action to a particular entity, contact the person listed in the
preceding FOR FURTHER INFORMATION CONTACT section.
B. Where can I get a copy of this document and other related
information?
In addition to being available in the docket, an electronic copy of
this proposal will also be available on the EPA's Web site. Following
signature by the EPA Administrator, a copy of this proposed action will
be posted on the EPA's Web site at the following address: http://www.epa.gov/airquality/oilandgas.
Additional information is available on the EPA's Residual Risk and
Technology Review (RTR) Web site at http://www.epa.gov/ttn/atw/rrisk/oarpg.html. This information includes the most recent version of the
rule, source category descriptions, detailed emissions and other data
that were used as inputs to the risk assessments.
C. What should I consider as I prepare my comments for the EPA?
Submitting CBI. Do not submit information containing CBI to the EPA
through http://www.regulations.gov or e-mail. Clearly mark the part or
all of the information that you claim to be CBI. For CBI information on
a disk or CD ROM that you mail to the EPA, mark the outside of the disk
or CD ROM as CBI and then identify electronically within the disk or CD
ROM the specific information that is claimed as CBI. In addition to one
complete version of the comment that includes information claimed as
CBI, a copy of the comment that does not contain the information
claimed as CBI must be submitted for inclusion in the public docket. If
you submit a CD ROM or disk that does not contain CBI, mark the outside
of the disk or CD ROM clearly that it does not contain CBI. Information
not marked as CBI will be included in the public docket and the EPA's
electronic public docket without prior notice. Information marked as
CBI will not be disclosed except in accordance with procedures set
forth in 40 CFR part 2. Send or deliver information identified as CBI
only to the following address: Roberto Morales, OAQPS Document Control
Officer (C404-02), Environmental Protection Agency, Office of Air
Quality Planning and Standards, Research Triangle Park, North Carolina
27711, Attention Docket ID Number EPA-HQ-OAR-2010-0505.
D. When will a public hearing occur?
We will hold three public hearings, one in the Dallas, Texas area,
one in Pittsburgh, Pennsylvania, and one in Denver, Colorado. If you
are interested in attending or speaking at one of the public hearings,
contact Ms. Joan Rogers at (919) 541-4487 by September 6, 2011. Details
on the public hearings will be provided in a separate notice and we
will specify the time and date of the public hearings on http://www.epa.gov/airquality/oilandgas. If no one requests to speak at one of
the public hearings by September 6, 2011, then that public hearing will
be cancelled without further notice.
III. Background Information
A. What are standards of performance and NSPS?
1. What is the statutory authority for standards of performance and
NSPS?
Section 111 of the Clean Air Act (CAA) requires the EPA
Administrator to list categories of stationary sources, if such sources
cause or contribute significantly to air pollution, which may
reasonably be anticipated to endanger public health or welfare. The EPA
must then issue performance standards for such source categories. A
performance standard reflects the degree of emission limitation
achievable through the application of the ``best system of emission
reduction'' (BSER) which the EPA determines has been adequately
demonstrated. The EPA may consider certain costs and nonair quality
health and environmental impact and energy requirements when
establishing performance standards. Whereas CAA section 112 standards
are issued for existing and new stationary sources, standards of
performance are issued for new and modified stationary sources. These
standards are referred to as new source performance standards (NSPS).
The EPA has the authority to define the source categories, determine
the pollutants for which standards should be developed, identify the
facilities within each source category to be covered and set the
emission level of the standards.
CAA section 111(b)(1)(B) requires the EPA to ``at least every 8
years review and, if appropriate, revise'' performance standards unless
the ``Administrator determines that such review is not appropriate in
light of readily available information on the efficacy'' of the
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standard. When conducting a review of an existing performance standard,
the EPA has discretion to revise that standard to add emission limits
for pollutants or emission sources not currently regulated for that
source category.
In setting or revising a performance standard, CAA section
111(a)(1) provides that performance standards are to ``reflect the
degree of emission limitation achievable through the application of the
best system of emission reduction which (taking into account the cost
of achieving such reduction and any nonair quality health and
environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated.'' In this notice, we refer
to this level of control as the BSER. In determining BSER, we typically
conduct a technology review that identifies what emission reduction
systems exist and how much they reduce air pollution in practice. Next,
for each control system identified, we evaluate its costs, secondary
air benefits (or disbenefits) resulting from energy requirements and
nonair quality impacts such as solid waste generation. Based on our
evaluation, we would determine BSER. The resultant standard is usually
a numerical emissions limit, expressed as a performance level (i.e., a
rate-based standard or percent control), that reflects the BSER.
Although such standards are based on the BSER, the EPA may not
prescribe a particular technology that must be used to comply with a
performance standard, except in instances where the Administrator
determines it is not feasible to prescribe or enforce a standard of
performance. Typically, sources remain free to elect whatever control
measures that they choose to meet the emission limits. Upon
promulgation, an NSPS becomes a national standard to which all new,
modified or reconstructed sources must comply.
2. What is the regulatory history regarding performance standards for
the oil and natural gas sector?
In 1979, the EPA listed crude oil and natural gas production on its
priority list of source categories for promulgation of NSPS (44 FR
49222, August 21, 1979). On June 24, 1985 (50 FR 26122), the EPA
promulgated an NSPS for the source category that addressed volatile
organic compound (VOC) emissions from leaking components at onshore
natural gas processing plants (40 CFR part 60, subpart KKK). On October
1, 1985 (50 FR 40158), a second NSPS was promulgated for the source
category that regulates sulfur dioxide (SO2) emissions from
natural gas processing plants (40 CFR part 60, subpart LLL). Other than
natural gas processing plants, EPA has not previously set NSPS for a
variety of oil and natural gas operations.
B. What are NESHAP?
1. What is the statutory authority for NESHAP?
Section 112 of the CAA establishes a two-stage regulatory process
to address emissions of hazardous air pollutants (HAP) from stationary
sources. In the first stage, after the EPA has identified categories of
sources emitting one or more of the HAP listed in section 112(b) of the
CAA, section 112(d) of the CAA calls for us to promulgate national
emission standards for hazardous air pollutants (NESHAP) for those
sources. ``Major sources'' are those that emit or have the potential to
emit (PTE) 10 tons per year (tpy) or more of a single HAP or 25 tpy or
more of any combination of HAP. For major sources, these technology-
based standards must reflect the maximum degree of emission reductions
of HAP achievable (after considering cost, energy requirements and
nonair quality health and environmental impacts) and are commonly
referred to as maximum achievable control technology (MACT) standards.
MACT standards are to reflect application of measures, processes,
methods, systems or techniques, including, but not limited to, measures
which, (1) reduce the volume of or eliminate pollutants through process
changes, substitution of materials or other modifications, (2) enclose
systems or processes to eliminate emissions, (3) capture or treat
pollutants when released from a process, stack, storage or fugitive
emissions point, (4) are design, equipment, work practice or
operational standards (including requirements for operator training or
certification) or (5) are a combination of the above. CAA section
112(d)(2)(A)-(E). The MACT standard may take the form of a design,
equipment, work practice or operational standard where the EPA first
determines either that, (1) a pollutant cannot be emitted through a
conveyance designed and constructed to emit or capture the pollutant or
that any requirement for or use of such a conveyance would be
inconsistent with law or (2) the application of measurement methodology
to a particular class of sources is not practicable due to
technological and economic limitations. CAA sections 112(h)(1)-(2).
The MACT ``floor'' is the minimum control level allowed for MACT
standards promulgated under CAA section 112(d)(3), and may not be based
on cost considerations. For new sources, the MACT floor cannot be less
stringent than the emission control that is achieved in practice by the
best-controlled similar source. The MACT floors for existing sources
can be less stringent than floors for new sources, but they cannot be
less stringent than the average emission limitation achieved by the
best-performing 12 percent of existing sources in the category or
subcategory (or the best-performing five sources for categories or
subcategories with fewer than 30 sources). In developing MACT
standards, we must also consider control options that are more
stringent than the floor. We may establish standards more stringent
than the floor based on the consideration of the cost of achieving the
emissions reductions, any nonair quality health and environmental
impacts and energy requirements.
The EPA is then required to review these technology-based standards
and to revise them ``as necessary (taking into account developments in
practices, processes, and control technologies)'' no less frequently
than every 8 years, under CAA section 112(d)(6). In conducting this
review, the EPA is not obliged to completely recalculate the prior MACT
determination. NRDC v. EPA, 529 F.3d 1077, 1084 (D.C. Cir. 2008).
The second stage in standard-setting focuses on reducing any
remaining ``residual'' risk according to CAA section 112(f). This
provision requires, first, that the EPA prepare a Report to Congress
discussing (among other things) methods of calculating risk posed (or
potentially posed) by sources after implementation of the MACT
standards, the public health significance of those risks, and the EPA's
recommendations as to legislation regarding such remaining risk. The
EPA prepared and submitted this report (Residual Risk Report to
Congress, EPA-453/R-99-001) in March 1999. Congress did not act in
response to the report, thereby triggering the EPA's obligation under
CAA section 112(f)(2) to analyze and address residual risk.
CAA section 112(f)(2) requires us to determine for source
categories subject to MACT standards, whether the emissions standards
provide an ample margin of safety to protect public health. If the MACT
standards for HAP ``classified as a known, probable, or possible human
carcinogen do not reduce lifetime excess cancer risks to the individual
most exposed to emissions from a source in the category or subcategory
to less than 1-in-1 million,'' the EPA must promulgate
[[Page 52742]]
residual risk standards for the source category (or subcategory), as
necessary, to provide an ample margin of safety to protect public
health. In doing so, the EPA may adopt standards equal to existing MACT
standards if the EPA determines that the existing standards are
sufficiently protective. NRDC v. EPA, 529 F.3d 1077, 1083 (D.C. Cir.
2008). (``If EPA determines that the existing technology-based
standards provide an ``ample margin of safety,'' then the Agency is
free to readopt those standards during the residual risk rulemaking.'')
The EPA must also adopt more stringent standards, if necessary, to
prevent an adverse environmental effect,\1\ but must consider cost,
energy, safety and other relevant factors in doing so.
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\1\ ``Adverse environmental effect'' is defined in CAA section
112(a)(7) as any significant and widespread adverse effect, which
may be reasonably anticipated to wildlife, aquatic life or natural
resources, including adverse impacts on populations of endangered or
threatened species or significant degradation of environmental
qualities over broad areas.
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Section 112(f)(2) of the CAA expressly preserves our use of a two-
step process for developing standards to address any residual risk and
our interpretation of ``ample margin of safety'' developed in the
National Emission Standards for Hazardous Air Pollutants: Benzene
Emissions from Maleic Anhydride Plants, Ethylbenzene/Styrene Plants,
Benzene Storage Vessels, Benzene Equipment Leaks, and Coke By-Product
Recovery Plants (Benzene NESHAP) (54 FR 38044, September 14, 1989). The
first step in this process is the determination of acceptable risk. The
second step provides for an ample margin of safety to protect public
health, which is the level at which the standards are set (unless a
more stringent standard is required to prevent, taking into
consideration costs, energy, safety, and other relevant factors, an
adverse environmental effect).
The terms ``individual most exposed,'' ``acceptable level,'' and
``ample margin of safety'' are not specifically defined in the CAA.
However, CAA section 112(f)(2)(B) preserves the interpretation set out
in the Benzene NESHAP, and the United States Court of Appeals for the
District of Columbia Circuit in NRDC v. EPA, 529 F.3d 1077, concluded
that the EPA's interpretation of subsection 112(f)(2) is a reasonable
one. See NRDC v. EPA, 529 F.3d at 1083 (D.C. Cir., ``[S]ubsection
112(f)(2)(B) expressly incorporates EPA's interpretation of the Clean
Air Act from the Benzene standard, complete with a citation to the
Federal Register''). (D.C. Cir. 2008). See also, A Legislative History
of the Clean Air Act Amendments of 1990, volume 1, p. 877 (Senate
debate on Conference Report). We notified Congress in the Residual Risk
Report to Congress that we intended to use the Benzene NESHAP approach
in making CAA section 112(f) residual risk determinations (EPA-453/R-
99-001, p. ES-11).
In the Benzene NESHAP, we stated as an overall objective:
* * * in protecting public health with an ample margin of
safety, we strive to provide maximum feasible protection against
risks to health from hazardous air pollutants by, (1) protecting the
greatest number of persons possible to an individual lifetime risk
level no higher than approximately 1-in-1 million; and (2) limiting
to no higher than approximately 1-in-10 thousand [i.e., 100-in-1
million] the estimated risk that a person living near a facility
would have if he or she were exposed to the maximum pollutant
concentrations for 70 years.
The Agency also stated that, ``The EPA also considers incidence
(the number of persons estimated to suffer cancer or other serious
health effects as a result of exposure to a pollutant) to be an
important measure of the health risk to the exposed population.
Incidence measures the extent of health risk to the exposed population
as a whole, by providing an estimate of the occurrence of cancer or
other serious health effects in the exposed population.'' The Agency
went on to conclude that ``estimated incidence would be weighed along
with other health risk information in judging acceptability.'' As
explained more fully in our Residual Risk Report to Congress, the EPA
does not define ``rigid line[s] of acceptability,'' but considers
rather broad objectives to be weighed with a series of other health
measures and factors (EPA-453/R-99-001, p. ES-11). The determination of
what represents an ``acceptable'' risk is based on a judgment of ``what
risks are acceptable in the world in which we live'' (Residual Risk
Report to Congress, p. 178, quoting the Vinyl Chloride decision at 824
F.2d 1165) recognizing that our world is not risk-free.
In the Benzene NESHAP, we stated that ``EPA will generally presume
that if the risk to [the maximum exposed] individual is no higher than
approximately 1-in-10 thousand, that risk level is considered
acceptable.'' 54 FR 38045. We discussed the maximum individual lifetime
cancer risk (or maximum individual risk (MIR)) as being ``the estimated
risk that a person living near a plant would have if he or she were
exposed to the maximum pollutant concentrations for 70 years.'' Id. We
explained that this measure of risk ``is an estimate of the upper bound
of risk based on conservative assumptions, such as continuous exposure
for 24 hours per day for 70 years.'' Id. We acknowledge that maximum
individual lifetime cancer risk ``does not necessarily reflect the true
risk, but displays a conservative risk level which is an upper-bound
that is unlikely to be exceeded.'' Id.
Understanding that there are both benefits and limitations to using
maximum individual lifetime cancer risk as a metric for determining
acceptability, we acknowledged in the 1989 Benzene NESHAP that
``consideration of maximum individual risk * * * must take into account
the strengths and weaknesses of this measure of risk.'' Id.
Consequently, the presumptive risk level of 100-in-1 million (1-in-10
thousand) provides a benchmark for judging the acceptability of maximum
individual lifetime cancer risk, but does not constitute a rigid line
for making that determination.
The Agency also explained in the 1989 Benzene NESHAP the following:
``In establishing a presumption for MIR, rather than a rigid line for
acceptability, the Agency intends to weigh it with a series of other
health measures and factors. These include the overall incidence of
cancer or other serious health effects within the exposed population,
the numbers of persons exposed within each individual lifetime risk
range and associated incidence within, typically, a 50-kilometer (km)
exposure radius around facilities, the science policy assumptions and
estimation uncertainties associated with the risk measures, weight of
the scientific evidence for human health effects, other quantified or
unquantified health effects, effects due to co-location of facilities
and co-emission of pollutants.'' Id.
In some cases, these health measures and factors taken together may
provide a more realistic description of the magnitude of risk in the
exposed population than that provided by maximum individual lifetime
cancer risk alone. As explained in the Benzene NESHAP, ``[e]ven though
the risks judged ``acceptable'' by the EPA in the first step of the
Vinyl Chloride inquiry are already low, the second step of the inquiry,
determining an ``ample margin of safety,'' again includes consideration
of all of the health factors, and whether to reduce the risks even
further.'' In the ample margin of safety decision process, the Agency
again considers all of the health risks and other health information
considered in the first step. Beyond that information, additional
factors relating to the appropriate level
[[Page 52743]]
of control will also be considered, including costs and economic
impacts of controls, technological feasibility, uncertainties and any
other relevant factors. Considering all of these factors, the Agency
will establish the standard at a level that provides an ample margin of
safety to protect the public health, as required by CAA section 112(f).
54 FR 38046.
2. How do we consider the risk results in making decisions?
As discussed in the previous section of this preamble, we apply a
two-step process for developing standards to address residual risk. In
the first step, the EPA determines if risks are acceptable. This
determination ``considers all health information, including risk
estimation uncertainty, and includes a presumptive limit on maximum
individual lifetime [cancer] risk (MIR) \2\ of approximately 1-in-10
thousand [i.e., 100-in-1 million].'' 54 FR 38045. In the second step of
the process, the EPA sets the standard at a level that provides an
ample margin of safety ``in consideration of all health information,
including the number of persons at risk levels higher than
approximately 1-in-1 million, as well as other relevant factors,
including costs and economic impacts, technological feasibility, and
other factors relevant to each particular decision.'' Id.
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\2\ Although defined as ``maximum individual risk,'' MIR refers
only to cancer risk. MIR, one metric for assessing cancer risk, is
the estimated risk were an individual exposed to the maximum level
of a pollutant for a lifetime.
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In past residual risk determinations, the EPA presented a number of
human health risk metrics associated with emissions from the category
under review, including: The MIR; the numbers of persons in various
risk ranges; cancer incidence; the maximum noncancer hazard index (HI);
and the maximum acute noncancer hazard. In estimating risks, the EPA
considered source categories under review that are located near each
other and that affect the same population. The EPA provided estimates
of the expected difference in actual emissions from the source category
under review and emissions allowed pursuant to the source category MACT
standard. The EPA also discussed and considered risk estimation
uncertainties. The EPA is providing this same type of information in
support of these actions.
The Agency acknowledges that the Benzene NESHAP provides
flexibility regarding what factors the EPA might consider in making our
determinations and how they might be weighed for each source category.
In responding to comment on our policy under the Benzene NESHAP, the
EPA explained that: ``The policy chosen by the Administrator permits
consideration of multiple measures of health risk. Not only can the MIR
figure be considered, but also incidence, the presence of noncancer
health effects, and the uncertainties of the risk estimates. In this
way, the effect on the most exposed individuals can be reviewed as well
as the impact on the general public. These factors can then be weighed
in each individual case. This approach complies with the Vinyl Chloride
mandate that the Administrator ascertain an acceptable level of risk to
the public by employing [her] expertise to assess available data. It
also complies with the Congressional intent behind the CAA, which did
not exclude the use of any particular measure of public health risk
from the EPA's consideration with respect to CAA section 112
regulations, and, thereby, implicitly permits consideration of any and
all measures of health risk which the Administrator, in [her] judgment,
believes are appropriate to determining what will `protect the public
health.' ''
For example, the level of the MIR is only one factor to be weighed
in determining acceptability of risks. The Benzene NESHAP explains ``an
MIR of approximately 1-in-10 thousand should ordinarily be the upper
end of the range of acceptability. As risks increase above this
benchmark, they become presumptively less acceptable under CAA section
112, and would be weighed with the other health risk measures and
information in making an overall judgment on acceptability. Or, the
Agency may find, in a particular case, that a risk that includes MIR
less than the presumptively acceptable level is unacceptable in the
light of other health risk factors.'' Similarly, with regard to the
ample margin of safety analysis, the Benzene NESHAP states that: ``EPA
believes the relative weight of the many factors that can be considered
in selecting an ample margin of safety can only be determined for each
specific source category. This occurs mainly because technological and
economic factors (along with the health-related factors) vary from
source category to source category.''
3. What is the regulatory history regarding NESHAP for the oil and
natural gas sector?
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. On February 12, 1998 (63 FR 7155), the
EPA amended the source category list to add Natural Gas Transmission
and Storage as a major source category.
On June 17, 1999 (64 FR 32610), the EPA promulgated MACT standards
for the Oil and Natural Gas Production and Natural Gas Transmission and
Storage major source categories. The Oil and Natural Gas Production
NESHAP (40 CFR part 63, subpart HH) contains standards for HAP
emissions from glycol dehydration process vents, storage vessels and
natural gas processing plant equipment leaks. The Natural Gas
Transmission and Storage NESHAP (40 CFR part 63, subpart HHH) contains
standards for glycol dehydration process vents.
In addition to these NESHAP for major sources, the EPA also
promulgated NESHAP for the Oil and Natural Gas Production area source
category on January 3, 2007 (72 FR 26). These area source standards,
which are based on generally available control technology, are also
contained in 40 CFR part 63, subpart HH. This proposed action does not
impact these area source standards.
C. What litigation is related to this proposed action?
On January 14, 2009, pursuant to section 304(a)(2) of the CAA,
WildEarth Guardians and the San Juan Citizens Alliance filed a
Complaint alleging that the EPA failed to meet its obligations under
CAA sections 111(b)(1)(B), 112(d)(6) and 112(f)(2) to take actions
relative to the review/revision of the NSPS and the NESHAP with respect
to the Oil and Natural Gas Production source category. On February 4,
2010, the Court entered a consent decree requiring the EPA to sign by
July 28, 2011,\3\ proposed standards and/or determinations not to issue
standards pursuant to CAA sections 111(b)(1)(B), 112(d)(6) and
112(f)(2) and to take final action by February 28, 2012.
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\3\ On April 27, 2011, pursuant to paragraph 10(a) of the
Consent Decree, the parties filed with the Court a written
stipulation that changes the proposal date from January 31, 2011, to
July 28, 2011, and the final action date from November 30, 2011, to
February 28, 2012.
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D. What is a sector-based approach?
Sector-based approaches are based on integrated assessments that
consider multiple pollutants in a comprehensive and coordinated manner
to manage emissions and CAA requirements. One of the many ways we can
address sector-based approaches is by reviewing multiple regulatory
programs together whenever possible, consistent with all
[[Page 52744]]
applicable legal requirements. This approach essentially expands the
technical analyses on costs and benefits of particular technologies, to
consider the interactions of rules that regulate sources. The benefit
of multi-pollutant and sector-based analyses and approaches includes
the ability to identify optimum strategies, considering feasibility,
cost impacts and benefits across the different pollutant types while
streamlining administrative and compliance complexities and reducing
conflicting and redundant requirements, resulting in added certainty
and easier implementation of control strategies for the sector under
consideration. In order to benefit from a sector-based approach for the
oil and gas industry, the EPA analyzed how the NSPS and NESHAP under
consideration relate to each other and other regulatory requirements
currently under review for oil and gas facilities. In this analysis, we
looked at how the different control requirements that result from these
requirements interact, including the different regulatory deadlines and
control equipment requirements that result, the different reporting and
recordkeeping requirements and opportunities for states to account for
reductions resulting from this rulemaking in their State Implementation
Plans (SIP). The requirements analyzed affect criteria pollutant, HAP
and methane emissions from oil and natural gas processes and cover the
NSPS and NESHAP reviews. As a result of the sector-based approach, this
rulemaking will reduce conflicting and redundant requirements. Also,
the sector-based approach facilitated the streamlining of monitoring,
recordkeeping and reporting requirements, thus, reducing administrative
and compliance complexities associated with complying with multiple
regulations. In addition, the sector-based approach promotes a
comprehensive control strategy that maximizes the co-control of
multiple regulated pollutants while obtaining emission reductions as
co-benefits.
IV. Oil and Natural Gas Sector
The oil and natural gas sector includes operations involved in the
extraction and production of oil and natural gas, as well as the
processing, transmission and distribution of natural gas. Specifically
for oil, the sector includes all operations from the well to the point
of custody transfer at a petroleum refinery. For natural gas, the
sector includes all operations from the well to the customer. The oil
and natural gas operations can generally be separated into four
segments: (1) Oil and natural gas production, (2) natural gas
processing, (3) natural gas transmission and (4) natural gas
distribution. Each of these segments is briefly discussed below.
Oil and natural gas production includes both onshore and offshore
operations. Production operations include the wells and all related
processes used in the extraction, production, recovery, lifting,
stabilization, separation or treating of oil and/or natural gas
(including condensate). Production components may include, but are not
limited to, wells and related casing head, tubing head and ``Christmas
tree'' piping, as well as pumps, compressors, heater treaters,
separators, storage vessels, pneumatic devices and dehydrators.
Production operations also include the well drilling, completion and
workover processes and includes all the portable non-self-propelled
apparatus associated with those operations. Production sites include
not only the ``pads'' where the wells are located, but also include
stand-alone sites where oil, condensate, produced water and gas from
several wells may be separated, stored and treated. The production
sector also includes the low pressure, small diameter, gathering
pipelines and related components that collect and transport the oil,
gas and other materials and wastes from the wells to the refineries or
natural gas processing plants. None of the operations upstream of the
natural gas processing plant are covered by the existing NSPS. Offshore
oil and natural gas production occurs on platform structures that house
equipment to extract oil and gas from the ocean or lake floor and that
process and/or transfer the oil and gas to storage, transport vessels
or onshore. Offshore production can also include secondary platform
structures connected to the platform structure, storage tanks
associated with the platform structure and floating production and
offloading equipment.
There are three basic types of wells: Oil wells, gas wells and
associated gas wells. Oil wells can have ``associated'' natural gas
that is separated and processed or the crude oil can be the only
product processed. Once the crude oil is separated from the water and
other impurities, it is essentially ready to be transported to the
refinery via truck, railcar or pipeline. We consider the oil refinery
sector separately from the oil and natural gas sector. Therefore, at
the point of custody transfer at the refinery, the oil leaves the oil
and natural gas sector and enters the petroleum refining sector.
Natural gas is primarily made up of methane. However, whether
natural gas is associated gas from oil wells or non-associated gas from
gas or condensate wells, it commonly exists in mixtures with other
hydrocarbons. These hydrocarbons are often referred to as natural gas
liquids (NGL). They are sold separately and have a variety of different
uses. The raw natural gas often contains water vapor, hydrogen sulfide
(H2S), carbon dioxide (CO2), helium, nitrogen and
other compounds. Natural gas processing consists of separating certain
hydrocarbons and fluids from the natural gas to produced ``pipeline
quality'' dry natural gas. While some of the processing can be
accomplished in the production segment, the complete processing of
natural gas takes place in the natural gas processing segment. Natural
gas processing operations separate and recover NGL or other non-methane
gases and liquids from a stream of produced natural gas through
components performing one or more of the following processes: Oil and
condensate separation, water removal, separation of NGL, sulfur and
CO2 removal, fractionation of natural gas liquid and other
processes, such as the capture of CO2 separated from natural
gas streams for delivery outside the facility. Natural gas processing
plants are the only operations covered by the existing NSPS.
The pipeline quality natural gas leaves the processing segment and
enters the transmission segment. Pipelines in the natural gas
transmission segment can be interstate pipelines that carry natural gas
across state boundaries or intrastate pipelines, which transport the
gas within a single state. While interstate pipelines may be of a
larger diameter and operated at a higher pressure, the basic components
are the same. To ensure that the natural gas flowing through any
pipeline remains pressurized, compression of the gas is required
periodically along the pipeline. This is accomplished by compressor
stations usually placed between 40 and 100 mile intervals along the
pipeline. At a compressor station, the natural gas enters the station,
where it is compressed by reciprocating or centrifugal compressors.
In addition to the pipelines and compressor stations, the natural
gas transmission segment includes underground storage facilities.
Underground natural gas storage includes subsurface storage, which
typically consists of depleted gas or oil reservoirs and salt dome
caverns used for storing natural gas. One purpose of this storage is
for load balancing (equalizing the receipt and delivery of natural
gas). At an underground storage site, there are typically other
processes,
[[Page 52745]]
including compression, dehydration and flow measurement.
The distribution segment is the final step in delivering natural
gas to customers. The natural gas enters the distribution segment from
delivery points located on interstate and intrastate transmission
pipelines to business and household customers. The delivery point where
the natural gas leaves the transmission segment and enters the
distribution segment is often called the ``citygate.'' Typically,
utilities take ownership of the gas at the citygate. Natural gas
distribution systems consist of thousands of miles of piping, including
mains and service pipelines to the customers. Distribution systems
sometimes have compressor stations, although they are considerably
smaller than transmission compressor stations. Distribution systems
include metering stations, which allow distribution companies to
monitor the natural gas in the system. Essentially, these metering
stations measure the flow of gas and allow distribution companies to
track natural gas as it flows through the system.
Emissions can occur from a variety of processes and points
throughout the oil and natural gas sector. Primarily, these emissions
are organic compounds such as methane, ethane, VOC and organic HAP. The
most common organic HAP are n-hexane and BTEX compounds (benzene,
toluene, ethylbenzene and xylenes). Hydrogen sulfide (H2S)
and sulfur dioxide (SO2) are emitted from production and
processing operations that handle and treat ``sour gas.'' Sour gas is
defined as natural gas with a maximum H2S content of 0.25
gr/100 scf (4ppmv) along with the presence of CO2.
In addition, there are significant emissions associated with the
reciprocating internal combustion engines and combustion turbines that
power compressors throughout the oil and natural gas sector. However,
emissions from internal combustion engines and combustion turbines are
covered by regulations specific to engines and turbines and, thus, are
not addressed in this action.
V. Summary of Proposed Decisions and Actions
Pursuant to CAA sections 111(b), 112(d)(2), 112(d)(6) and 112(f),
we are proposing to revise the NSPS and NESHAP relative to oil and gas
to include the standards and requirements summarized in this section.
More details of the rationale for these proposed standards and
requirements are provided in sections VI and VII of this preamble. In
addition, as part of these rationale discussions, we solicit public
comment and data relevant to several issues. The comments we receive
during the public comment period will help inform the rule development
process as we work toward promulgating a final action.
A. What are the proposed revisions to the NSPS?
We reviewed the two NSPS that apply to the oil and natural gas
industry. Based on our review, we believe that the requirements at 40
CFR part 60, subpart KKK, should be updated to reflect requirements in
40 CFR part 60, subpart VVa for controlling VOC equipment leaks at
processing plants. We also believe that the requirements at 40 CFR part
60, subpart LLL, for controlling SO2 emissions from natural
gas processing plants should be strengthened for facilities with the
highest sulfur feed rates and the highest H2S
concentrations. For a more detailed discussion, please see section
VI.B.1 of this preamble.
In addition, there are significant VOC emissions from oil and
natural gas operations that are not covered by the two existing NSPS,
including other emissions at processing plants and emissions from
upstream production, as well as transmission and storage facilities. In
the 1984 notice that listed source categories (including Oil and
Natural Gas) for promulgation of NSPS, we noted that there were
discrepancies between the source category names on the list and those
in the background document, and we clarified our intent to address all
sources under an industry heading at the same time. See 44 FR 49222,
49224-49225.\4\ We, therefore, believe that the currently listed Oil
and Natural Gas source category covers all operations in this industry
(i.e., production, processing, transmission, storage and distribution).
To the extent there are oil and gas operations not covered by the
currently listed Oil and Natural Gas source category, pursuant to CAA
section 111(b), we hereby modify the category list to include all
operations in the oil and natural gas sector. Section 111(b) of the CAA
gives the EPA broad authority and discretion to list and establish NSPS
for a category that, in the Administrator's judgment, causes or
contributes significantly to air pollution which may reasonably be
anticipated to endanger public health or welfare. Pursuant to CAA
section 111(b), we are modifying the source category list to include
any oil and gas operation not covered by the current listing and
evaluating emissions from all oil and gas operations at the same time.
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\4\ The Notice further states that ``The Administrator may also
concurrently develop standards for sources which are not on the
priority list.'' 44 FR at 49225.
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We are also proposing standards for several new oil and natural gas
affected facilities. The proposed standards would apply to affected
facilities that commence construction, reconstruction or modification
after August 23, 2011. These standards, which include requirements for
VOC, would be contained in a new subpart, 40 CFR part 60, subpart OOOO.
Subpart OOOO would incorporate 40 CFR part 60, subpart KKK and 40 CFR
part 60, subpart LLL, thereby having in this one subpart, all standards
that are applicable to the new and modified affected facilities
described above. We also propose to amend the title of subparts KKK and
LLL, accordingly, to apply only to affected facilities already subject
to those subparts. Those operations would not become subject to subpart
OOOO unless they triggered applicability based on new or modified
affected facilities under subpart OOOO.
We are proposing operational standards for completions of
hydraulically fractured gas wells. Based on our review, we identified
two subcategories of fractured gas wells for which well completions are
conducted. For non-exploratory and non-delineation wells, the proposed
operational standards would require reduced emission completion (REC),
commonly referred to as ``green completion,'' in combination with pit-
flaring of gas not suitable for entering the gathering line. For
exploratory and delineation wells (these wells generally are not in
close proximity to a gathering line), we proposed an operational
standard that would require pit flaring. Well completions subject to
the standards would be limited to gas well completions following
hydraulic fracturing operations. These completions include those
conducted at newly drilled and fractured wells, as well as completions
conducted following refracturing operations at various times over the
life of the well. We have determined that a completion associated with
refracturing performed at an existing well (i.e., a well existing prior
to August 23, 2011) is considered a modification under CAA section
111(a), because physical change occurs to the existing well resulting
in emissions increase during the refracturing and completion operation.
A detailed discussion of this determination is presented in the
Technical Support Document (TSD) in the docket. Therefore, the proposed
standards would apply to completions at new gas wells that are
fractured or
[[Page 52746]]
refractured along with completions associated with fracturing or
refracturing of existing gas wells. The modification determination and
resultant applicability of NSPS to the completion operation following
fracturing or refracturing of existing gas wells (i.e., wells existing
before August 23, 2011 would be limited strictly to the wellhead, well
bore, casing and tubing, and any conveyance through which gas is vented
to the atmosphere and not be extended beyond the wellhead to other
ancillary components that may be at the well site such as existing
storage vessels, process vessels, separators, dehydrators or any other
components or apparatus.
We are also proposing VOC standards to reduce emissions from gas-
driven pneumatic devices. We are proposing that each pneumatic device
is an affected facility. Accordingly, the proposed standards would
apply to each newly installed pneumatic device (including replacement
of an existing device). At gas processing plants, we are proposing a
zero emission limit for each individual pneumatic controller. The
proposed emission standards would reflect the emission level achievable
from the use of non-gas-driven pneumatic controllers. At other
locations, we are proposing a bleed limit of 6 standard cubic feet of
gas per hour for an individual pneumatic controller, which would
reflect the emission level achievable from the use of low bleed gas-
driven pneumatic controllers. In both cases, the standards provide
exemptions for certain applications based on functional considerations.
In addition, the proposed rule would require measures to reduce VOC
emissions from centrifugal and reciprocating compressors. As explained
in more detail below in section VI.B.4, we are proposing equipment
standards for centrifugal compressors. The proposed standards would
require the use of dry seal systems. However, we are aware that some
owners and operators may need to use centrifugal compressors with wet
seals, and we are soliciting comment on the suitability of a compliance
option allowing the use of wet seals combined with routing of emissions
from the seal liquid through a closed vent system to a control device
as an acceptable alternative to installing dry seals.
Our review of reciprocating compressors found that piston rod
packing wear produces fugitive emissions that cannot be captured and
conveyed to a control device. As a result, we are proposing operational
standards for reciprocating compressors, such that the proposed rule
would require replacement of the rod packing based on hours of usage.
The owner or operator of a reciprocating compressor affected facility
would be required to monitor the duration (in hours) that the
compressor is operated. When the hours of operation reaches 26,000
hours, the owner or operator would be required to change the rod
packing immediately. However, to avoid unscheduled shutdowns when
26,000 hours is reached, owners and operators could track hours of
operation such that packing replacement could be coordinated with
planned maintenance shutdowns before hours of operation reached 26,000.
Some operators may prefer to replace the rod packing on a fixed
schedule to ensure that the hours of operation would not reach 26,000
hours. We solicit comment on the appropriateness of a fixed replacement
frequency and other considerations that would be associated with
regular replacement.
We are also proposing VOC standards for new or modified storage
vessels. The proposed rule, which would apply to individual vessels,
would require that vessels meeting certain specifications achieve at
least 95-percent reduction in VOC emissions. Requirements would apply
to vessels with a throughput of 1 barrel of condensate per day or 20
barrels of crude oil per day. These thresholds are equivalent to VOC
emissions of about 6 tpy.
For gas processing plants, we are updating the requirements for
leak detection and repair (LDAR) to reflect procedures and leak
thresholds established by 40 CFR 60, subpart VVa. The existing NSPS
requires 40 CFR part 60, subpart VV procedures and thresholds.
For 40 CFR part 60, subpart LLL, which regulates SO2
emissions from natural gas processing plants, we determined that
affected facilities with sulfur feed rate of at least 5 long tons per
day or H2S concentration in the acid gas stream of at least
50 percent can achieve up to 99.9-percent SO2 control, which
is greater than the existing standard. Therefore, we are proposing
revision to the performance standards in subpart LLL as a result of
this review. For a more detailed discussion of this proposed
determination, please see section VI.B.1 of this preamble.
We are proposing to address compliance requirements for periods of
startup, shutdown and malfunction (SSM) for 40 CFR part 60, subpart
OOOO. The SSM changes are discussed in detail in section VI.B.5 below.
In addition, we are proposing to incorporate the requirements in 40 CFR
part 60, subpart KKK and 40 CFR part 60, subpart LLL into the new
subpart OOOO so that all requirements applicable to the new and
modified facilities would be in one subpart. This would simplify and
streamline compliance efforts on the part of the oil and natural gas
industry and could minimize duplication of notification, recordkeeping
and reporting.
B. What are the proposed decisions and actions related to the NESHAP?
This section summarizes the results of our RTR for the Oil and
Natural Gas Production and the Natural Gas Transmission and Storage
source categories and our proposed decisions concerning these two 1999
NESHAP.
1. Addressing Unregulated Emissions Sources
Pursuant to CAA sections 112(d)(2) and (3), we are proposing MACT
standards for subcategories of glycol dehydrators for which standards
were not previously developed (hereinafter referred to as the ``small
dehydrators''). In the Oil and Natural Gas Production source category,
the subcategory consists of glycol dehydrators with an actual annual
average natural gas flowrate less than 85,000 standard cubic meters per
day (scmd) or actual average benzene emissions less than 0.9 megagrams
per year (Mg/yr). In the Natural Gas Transmission and Storage source
category, the subcategory consists of glycol dehydrators with an actual
annual average natural gas flowrate less than 283,000 scmd or actual
average benzene emissions less than 0.9 Mg/yr.
The proposed MACT standards for the subcategory of small
dehydrators at oil and gas production facilities would require that
existing affected sources meet a unit-specific BTEX limit of 1.10 x
10-\4\ grams BTEX/standard cubic meters (scm)-parts per
million by volume (ppmv) and that new affected sources meet a BTEX
limit of 4.66 x 10-\6\ grams BTEX/scm-ppmv. At natural gas
transmission and storage affected sources, the proposed MACT standard
for the subcategory of small dehydrators would require that existing
affected sources meet a unit-specific BTEX emission limit of 6.42 x
10-\5\ grams BTEX/scm-ppmv and that new affected sources
meet a BTEX limit of 1.10 x 10-\5\ grams BTEX/scm-ppmv.
We are also proposing MACT standards for storage vessels that are
currently not regulated under the Oil and Natural Gas Production
NESHAP. The current MACT standards apply only to storage vessels with
the potential for flash emissions (PFE). As explained in section VII,
the original MACT analysis
[[Page 52747]]
accounted for all storage vessels. We are, therefore, proposing to
apply the current MACT standards of 95-percent emission reduction to
every storage vessel at major source oil and natural gas production
facilities. In conjunction with this change, we are proposing to amend
the definition of associated equipment to exclude all storage vessels,
and not just those with the PFE, from being considered ``associated
equipment.'' This means that emissions from all storage vessels, and
not just those from storage vessels with the PFE, are to be included in
the major source determination.
2. What are the proposed decisions and actions related to the risk
review?
For both the Oil and Natural Gas Production and the Natural Gas
Transmission and Storage source categories, we find that the current
levels of emissions allowed by the MACT reflect acceptable levels of
risk; however, the level of emissions allowed by the alternative
compliance option for glycol dehydrator MACT (i.e., the option of
reducing benzene emissions to less than 0.9 Mg/yr in lieu of the MACT
standard of 95-percent control) reflects an unacceptable level of risk.
We are, therefore, proposing to eliminate the 0.9 Mg/yr alternative
compliance option.
In addition, we are proposing that the MACT for these two oil and
gas source categories, as revised per above, provide an ample margin of
safety to protect public health and prevent adverse environmental
effects.
3. What are the proposed decisions and actions related to the
technology reviews of the existing NESHAP?
For both the Oil and Natural Gas Production and the Natural Gas
Transmission and Storage source categories, we are proposing no
revisions to the existing NESHAP pursuant to section 112(d)(6) of the
CAA.
4. What other actions are we proposing?
We are proposing an alternative performance test for non-flare,
combustion control devices. This test is to be conducted by the
combustion control device manufacturer to demonstrate the destruction
efficiency achieved by a specific model of combustion control device.
This would allow a source to purchase a performance tested device for
installation at their site without being required to conduct a site-
specific performance test. A definition for ``flare'' is being proposed
in the NESHAP to clarify which combustion control devices fall under
the manufacturers' performance testing alternative, and to clarify
which devices must be performance tested.
We are also proposing to: Revise the parametric monitoring
calibration provisions; require periodic performance testing where
applicable; remove the allowance of a design analysis for all control
devices other than condensers; remove the requirement for a minimum
residence time for an enclosed combustion device; and add recordkeeping
and reporting requirements to document carbon replacement intervals.
These changes are being proposed to bring the NESHAP up-to-date based
on what we have learned regarding control devices and compliance since
the original promulgation date.
In addition, we are proposing the elimination of the SSM exemption
in the Oil and Natural Gas Production and the Natural Gas Transmission
and Storage NESHAP. As discussed in more detail below in section VII,
consistent with Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2010), the
EPA is proposing that the established standards in these two NESHAP
apply at all times. We are proposing to revise Table 2 to both 40 CFR
part 63, subpart HH and 40 CFR part 63, subpart HHH to indicate that
certain 40 CFR part 63 general provisions relative to SSM do not apply,
including: 40 CFR 63.6 (e)(1)(i) \5\ and (ii), 40 CFR 63.6(e)(3) (SSM
plan requirement), 40 CFR 63.6(f)(1); 40 CFR 63.7(e)(1), 40 CFR
63.8(c)(1)(i) and (iii), and the last sentence of 40 CFR 63.8(d)(3); 40
CFR 63.10(b)(2)(i),(ii), (iv) and (v); 40 CFR 63.10(c)(10), (11) and
(15); and 40 CFR 63.10(d)(5). We are also proposing to: (1) Revise 40
CFR 63.771(d)(4)(i) and 40 CFR 63.1281(d)(4)(i) regarding operation of
the control device to be consistent with the SSM compliance
requirements; and (2) revise the SSM-associated reporting and
recordkeeping requirements in 40 CFR 63.774, 40 CFR 63.775, 40 CFR
63.1284 and 40 CFR 63.1285 to require reporting and recordkeeping for
periods of malfunction. In addition, as explained below, we are
proposing to add an affirmative defense to civil penalties for
exceedances of emission limits caused by malfunctions, as well as
criteria for establishing the affirmative defense.
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\5\ 40 CFR 63.6(e)(1)(i) requires owners or operators to act
according to the general duty to ``operate and maintain any affected
source, including associated air pollution control equipment and
monitoring equipment, in a manner consistent with safety and good
air pollution control practices for minimizing emissions.'' This
general duty to minimize is included in our proposed standard at 40
CFR 63.783(b)(1).
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The EPA has attempted to ensure that we have neither overlooked nor
failed to propose to remove from the existing text any provisions that
are inappropriate, unnecessary or redundant in the absence of the SSM
exemption, nor included any such provisions in the proposed new
regulatory language. We are specifically seeking comment on whether
there are any such provisions that we have inadvertently overlooked or
incorporated.
We are also revising the applicability provisions of 40 CFR part
63, subpart HH to clarify requirements regarding PTE determination and
the scope of a facility subject to subpart HH. Lastly, we are proposing
several editorial corrections and plain language revisions to improve
these rules.
C. What are the proposed notification, recordkeeping and reporting
requirements for this proposed action?
1. What are the proposed notification, recordkeeping and reporting
requirements for the proposed NSPS?
The proposed 40 CFR part 60, subpart OOOO includes new requirements
for several operations for which there are no existing Federal
standards. Most notably, as discussed in sections V.A and VI.B of this
preamble, the proposed NSPS will cover completions and recompletions of
hydraulically fractured gas wells. We estimate that over 20,000
completions and recompletions annually will be subject to the proposed
requirements. Given the number of these operations, we believe that
notification and reporting must be streamlined to the extent possible
to minimize undue burden on owners and operators, as well as state,
local and tribal agencies. In section V.D of this preamble, we discuss
some innovative implementation approaches being considered and seek
comment on these and other potential methods of streamlining
notification and reporting for well completions covered by the proposed
rule.
Owners or operators are required to submit initial notifications
and annual reports, and to retain records to assist in documenting that
they are complying with the provisions of the NSPS. These notification,
recordkeeping and reporting activities include both requirements of the
40 CFR part 60 General Provisions, as well as requirements specific to
40 CFR part 60, subpart OOOO.
Owners or operators of affected facilities (except for pneumatic
controller and gas wellhead affected
[[Page 52748]]
sources) must submit an initial notification within 1 year after
becoming subject to 40 CFR part 60, subpart OOOO or by 1 year after the
publication of the final rule in the Federal Register, whichever is
later. For pneumatic controllers, owners and operators are not required
to submit an initial notification, but instead are required to report
the installation of these affected facilities in their facility's
annual report. Owners or operators of wellhead affected facilities
(well completions) would also be required to submit a 30-day advance
notification of each well completion subject to the NSPS. In addition,
annual reports are due 1 year after initial startup date for your
affected facility or 1 year after the date of publication of the final
rule in the Federal Register, whichever is later. The notification and
annual reports must include information on all affected facilities
owned or operated that were new, modified or reconstructed sources
during the reporting period. A single report may be submitted covering
multiple affected facilities, provided that the report contains all the
information required by 40 CFR 60.5420(b). This information includes
general information on the facility (i.e., company name and address,
etc.), as well as information specific to individual affected
facilities.
For wellhead affected facilities, this information includes details
of each well completion during the period, including duration of
periods of gas recovery, flaring and venting. For centrifugal
compressor affected facilities, information includes documentation that
the compressor is fitted with dry seals. For reciprocating compressors,
information includes the cumulative hours of operation of each
compressor and records of rod packing replacement.
Information for pneumatic device affected facilities includes
location and manufacturer specifications of each pneumatic controller
installed during the period and documentation that supports any
exemption claimed allowing use of high bleed controllers. For
controllers installed at gas processing plants, the owner or operator
would document the use of non-gas driven devices. For controllers
installed in locations other than at gas processing plants, owners or
operators would provide manufacturer's specifications that document
bleed rate not exceeding 6 cubic feet per hour.
For storage vessel affected facilities, required report information
includes information that documents control device compliance, if
applicable. For vessels with throughputs below 1 barrel of condensate
per day and 21 barrels of crude oil per day, required information also
includes calculations or other documentation of the throughput. For
onshore gas processing plants, semi-annual reports are required, and
include information on number of pressure relief devices, number of
pressure relief devices for which leaks were detected and pressure
relief devices for which leaks were not repaired, as required in 40 CFR
60.5396 of subpart OOOO.
Records must be retained for 5 years and generally consist of the
same information required in the initial notification and annual and
semiannual reports.
2. What are the proposed amendments to notification, recordkeeping and
reporting requirements for the NESHAP?
We are proposing to revise certain recordkeeping requirements of 40
CFR part 63, subpart HH and 40 CFR part 63, subpart HHH. Specifically,
we are proposing that facilities using carbon adsorbers as a control
device keep records of their carbon replacement schedule and records
for each carbon replacement. In addition, owners and operators are
required to keep records of the occurrence and duration of each
malfunction or operation of the air pollution control equipment and
monitoring equipment.
In addition, in conjunction with the proposed MACT standards for
small glycol dehydration units and storage vessels that do not have the
PFE in the proposed amendment to 40 CFR part 63, subpart HH, we are
proposing that owners and operators of affected small glycol
dehydration units and storage vessels submit an initial notification
within 1 year after becoming subject to subpart HH or by 1 year after
the publication of the final rule in the Federal Register, whichever is
later.
Similarly, in conjunction with the proposed MACT standards for
small glycol dehydration units in the proposed 40 CFR part 63, subpart
HHH amendments, we are proposing that owners and operators of small
glycol dehydration units submit an initial notification within 1 year
after becoming subject to subpart HHH or by 1 year after the
publication of the final rule in the Federal Register, whichever is
later. Affected sources under either 40 CFR part 63, subpart HH or
subpart HHH that plan to be area sources by the compliance dates will
be required to submit a notification describing their schedule for the
actions planned to achieve area source status.
The proposed amendments to the NESHAP also include additional
requirements for the contents of the periodic reports. For both 40 CFR
part 63, subpart HH and 40 CFR part 63, subpart HHH, we are proposing
that the periodic reports also include periodic test results and
information regarding any carbon replacement events that occurred
during the reporting period.
3. How is information submitted using the Electronic Reporting Tool
(ERT)?
Performance test data are an important source of information that
the EPA uses in compliance determinations, developing and reviewing
standards, emission factor development, annual emission rate
determinations and other purposes. In these activities, the EPA has
found it ineffective and time consuming, not only for owners and
operators, but also for regulatory agencies, to locate, collect and
submit performance test data because of varied locations for data
storage and varied data storage methods. In recent years, though, stack
testing firms have typically collected performance test data in
electronic format, making it possible to move to an electronic data
submittal system that would increase the ease and efficiency of data
submittal and improve data accessibility.
Through this proposal, the EPA is taking a step to increase the
ease and efficiency of data submittal and improve data accessibility.
Specifically, the EPA is proposing that owners and operators of oil and
natural gas sector facilities submit electronic copies of required
performance test reports to the EPA's WebFIRE database. The WebFIRE
database was constructed to store performance test data for use in
developing emission factors. A description of the WebFIRE database is
available at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main.
As proposed above, data entry would be through an electronic
emissions test report structure called the Electronic Reporting Tool
(ERT). The ERT will be able to transmit the electronic report through
the EPA's Central Data Exchange network for storage in the WebFIRE
database making submittal of data very straightforward and easy. A
description of the ERT can be found at http://www.epa.gov/ttn/chief/ert/ert_tool.html.
The proposal to submit performance test data electronically to the
EPA would apply only to those performance tests conducted using test
methods that will be supported by the ERT. The ERT contains a specific
electronic data entry form for most of the commonly used EPA reference
methods. A listing of the pollutants and test methods supported by the
ERT is available at http://
[[Page 52749]]
www.epa.gov/ttn/chief/ert/ert_tool.html. We believe that industry
would benefit from this proposed approach to electronic data submittal.
Having these data, the EPA would be able to develop improved emission
factors, make fewer information requests, and promulgate better
regulations.
One major advantage of the proposed submittal of performance test
data through the ERT is a standardized method to compile and store much
of the documentation required to be reported by this rule. Another
advantage is that the ERT clearly states testing information that would
be required. Another important benefit of submitting these data to the
EPA at the time the source test is conducted is that it should
substantially reduce the effort involved in data collection activities
in the future. When the EPA has performance test data in hand, there
will likely be fewer or less substantial data collection requests in
conjunction with prospective required residual risk assessments or
technology reviews. This would result in a reduced burden on both
affected facilities (in terms of reduced manpower to respond to data
collection requests) and the EPA (in terms of preparing and
distributing data collection requests and assessing the results).
State, local and tribal agencies could also benefit from more
streamlined and accurate review of electronic data submitted to them.
The ERT would allow for an electronic review process rather than a
manual data assessment making review and evaluation of the source
provided data and calculations easier and more efficient. Finally,
another benefit of the proposed data submittal to WebFIRE
electronically is that these data would greatly improve the overall
quality of existing and new emissions factors by supplementing the pool
of emissions test data for establishing emissions factors and by
ensuring that the factors are more representative of current industry
operational procedures. A common complaint heard from industry and
regulators is that emission factors are outdated or not representative
of a particular source category. With timely receipt and incorporation
of data from most performance tests, the EPA would be able to ensure
that emission factors, when updated, represent the most current range
of operational practices. In summary, in addition to supporting
regulation development, control strategy development and other air
pollution control activities having an electronic database populated
with performance test data would save industry, state, local, tribal
agencies and the EPA significant time, money and effort while also
improving the quality of emission inventories and, as a result, air
quality regulations.
D. What are the innovative compliance approaches being considered?
Given the potential number and diversity of sources affected by
this action, we are exploring optional approaches to provide the
regulated community, the regulators and the public a more effective
mechanism that maximizes compliance and transparency while minimizing
burden.
Under a traditional approach, owners or operators would provide
notifications and keep records of information required by the NSPS. In
addition, they would certify compliance with the NSPS as part of a
required annual report that would include compliance-related
information, such as details of each well completion event and
information documenting compliance with other requirements of the NSPS.
The EPA, state or local agency would then physically inspect the
affected facilities and/or audit the records retained by the owner or
operator. As an alternative to the traditional approach, we are seeking
an innovative way to provide for more transparency to the public and
less burden on the regulatory agencies and owners and operators,
especially as it relates to modification of existing sources through
recompletions of hydraulically fractured gas wells. These innovative
approaches would provide compliance assurance in light of the absence
of requirements for CAA title V permitting of non-major sources.
Section V.E of this preamble discusses permitting implications
associated with the NSPS and presents a proposed rationale for
exempting non-major sources subject to the NSPS from title V permitting
requirements. As discussed in sections V.A, V.C and VI.B of this
preamble, the proposed NSPS will cover completions and recompletions of
hydraulically fractured gas wells. We estimate that over 20,000
completions and recompletions annually will be subject to the proposed
requirements. As a result, we believe that notification and reporting
associated with well completions must be streamlined to the extent
possible to minimize undue burden on owners and operators, as well as
state, local and tribal agencies. Though the requirements being
proposed here are based on the traditional approach to compliance and
do not include specific regulatory provisions for innovative compliance
tools, we have included discussions below that describe how some of
these optional tools could work, and we will consider providing for
such options in the final action. Further, we request comments and
suggestions on all aspects of the innovative compliance approaches
discussed below and how they may be implemented appropriately. We are
seeking comment regarding the scope of application of one or more of
these approaches, i.e., which provisions of the standards being
proposed here would be suitable for specific compliance approaches, and
whether the approaches should be alternatives to the requirements in
the regulations.
The guiding principles we are following in considering these
approaches to compliance are: (1) Simplicity and ease of understanding
and implementation; (2) transparency and public accessibility; (3)
electronic implementation where appropriate; and (4) encouragement of
compliance by making compliance easier than noncompliance. Below are
some tools that, when used in tandem with emissions limits and
operational standards, the Agency believes could both assure compliance
and transparency, while minimizing burden on affected sources and
regulatory agencies.
1. Registration of Wells and Advance Notification of Planned
Completions
Although the proposed NSPS will not require approval to drill or
complete wells, it is important that regulatory agencies know when
completions of hydraulically fractured wells are to be performed.
Notification should occur sufficiently in advance to allow for
inspections or audits to certify or verify that the operator will have
in place and use the appropriate controls during the completion. To
that end, the proposed NSPS requires a 30-day advance notification of
each completion or recompletion of a hydraulically fractured gas well.
The advance notification would require that owners or operators provide
the anticipated date of the completion, the geographic coordinates of
the well and identifying information concerning the owner or operator
and responsible company official. We believe this notification
requirement serves as the registration requirement and could be
streamlined through optional electronic reporting with web-based public
access or other methods. We seek comment on potential methodologies
that would minimize burden on operators, while providing timely and
useful information for regulators and the public. We also solicit
comment on provisions for a follow-up notification one or two days
before an impending completion via
[[Page 52750]]
telephone or by electronic means, since it is difficult to predict
exactly when a well will be ready for completion a month in advance.
However, we would expect an owner or operator to provide the follow-up
notification only in cases where the completion date was expected to
deviate from the original date provided. We ask for suggestions
regarding how much advance notification is needed and the most
effective method of providing sufficient and accurate advance
notification of well completions.
2. Third Party Verification
To complement the annual compliance certification required under
the proposed NSPS, we are considering and seeking comment on the
potential use of third party verification to assure compliance. Since
the emission sources in the oil and natural gas sector, especially well
completions, are widely geographically dispersed (often in very remote
locations), compliance assurance can be very difficult and burdensome
for state, local and tribal agencies and EPA permitting staff,
inspectors and compliance officers. Additionally, we believe that
verification of the data collection, compilation and calculations by an
independent and impartial third party could facilitate the
demonstration of compliance for the public. Verification of emissions
data can also be beneficial to owners and operators by providing
certainty of compliance status.
As mentioned above, notification and reporting requirements
associated with well completions are likely applications for third
party verification used in tandem with the required annual compliance
certification. The third party verification program could be used in a
variety of ways to ease regulatory burden on the owners and operators
and to leverage compliance assurance efforts of the EPA and state,
local and tribal agencies. The third party agent could serve as a
clearinghouse for notifications, records and annual compliance
certifications submitted by owners and operators. This would provide
online access to completion information by regulatory agencies and the
public. Having notifications submitted to the clearinghouse would
relieve state, local and tribal agencies of the burden of receiving
thousands of paper or e-mail well completion notifications each year,
yet still provide them quick access to the information. Using a third
party agent, it is possible that notifications of well completions
could be submitted with an advance period much less than 30 days that
could make a 2 day follow-up notification unnecessary. The
clearinghouse could also house information on past completions and
copies of compliance certifications. We seek comment on whether annual
reports for well completions would be needed if a suitable third party
verification program was in place and already housed that same
information. We also solicit comment on the range of potential
activities the third party verification program could handle with
regard to well completions.
In this proposed action, there are also provisions for applying
third party verification to the required electronic reporting using the
ERT (see section V.C.3 above for a discussion of the ERT). As stated
above, all sources must use the ERT to submit all performance test
reports (required in 40 CFR parts 60, 61 and 63) to the EPA. There is
an option in the ERT for state, local and tribal agencies to review and
verify that the information submitted to the EPA is truthful, accurate
and complete. Third party verifiers could be contractors or other
personnel familiar with oil and natural gas exploration and production.
We are seeking comment on appropriate third party reviewers and
qualifications and registration requirements under such a program. We
want to state clearly here that third party verification would not
supersede or substitute for inspections or audit of data and
information by state, local and tribal agencies and the EPA.
Potential issues with third party verification include costs
incurred by industry and approval of third party verifiers. The cost of
third party verification would be borne by the affected industries. We
are seeking comment on whether third party verification paid for by
industry would result in impartial, accurate and complete data
information. The EPA, working with state, local and tribal agencies and
industry, would expect to develop guidance for third party verifiers.
We are seeking comment on whether or not the EPA should approve third
party verifiers.
3. Electronic Reporting Using Existing Mechanisms
The proposed 40 CFR part 60, subpart OOOO and final Greenhouse Gas
(GHG) Mandatory Reporting Rule, 40 CFR part 98, subpart W, provide
details on flare and vented emission sources and how to estimate their
emissions. We solicit comment on requiring sources to electronically
submit their emissions data for the oil and gas rules proposed here.
The EPA's Electronic Greenhouse Gas Reporting Tool (e-GGRT) for 40 CFR
part 98, subpart W, while used to report emissions at the emissions
source level (e.g., well completions, well unloading, compressors, gas
plant leaks, etc.), will aggregate emissions at the basin level for e-
reporting purposes. As a result, it may be difficult to merge reporting
under NSPS subpart OOOO with GHG Reporting Rule subpart W methane
reporting, especially if manual reporting is used. However, since the
operator would have these emissions details at the individual well
level (because that will be how they would develop their basin-wide
estimates), we do not believe it would be a significant burden to
require owners or operators to report the data they already have for
subpart W in an ERT for NSPS and NESHAP compliance purposes. However,
if the e-GGRT is not structured to provide for reporting of other
pollutants besides GHG (e.g., VOC and HAP), then there may be some
modification of the database required to accommodate the other
pollutants.
4. Provisions for Encouraging Innovative Technology
The oil and natural gas industry has a long history of innovation
in developing new exploration and production methods, along with
techniques to minimize product losses and reduce adverse environmental
impacts. These efforts are often undertaken with tremendous amounts of
research, including pilot applications at operating facilities in the
field. Absent regulation, these developmental activities, some of which
ultimately are not successful, can proceed without risk of violation of
any standards. However, as more emission sources in this source
category are covered by regulation, as in the case of the action being
proposed here, there likely will be situations where innovation and
development of new control techniques potentially could be stifled by
risk of violation.
We believe it is important to facilitate, not hinder, innovation
and continued development of new technology that can result in enhanced
environmental performance of facilities and sources affected by the
EPA's regulations. However, any approaches to accommodate technology
development must be designed and implemented in accordance with the CAA
and other statutes. We seek comment on approaches that may be suitable
for allowing temporary field testing of technology in development.
These approaches could include not only established procedures under
the CAA and its implementing regulations, but new ways to apply or
interpret these provisions to avoid impeding
[[Page 52751]]
innovation while remaining environmentally responsible and legal.
E. How does the NSPS relate to permitting of sources?
1. How does this action affect permitting requirements?
The proposed rules do not change the Federal requirements for
determining whether oil and gas sources are major sources for purposes
of nonattainment major New Source Review (NSR), prevention of
significant deterioration, CAA title V, or HAP major sources pursuant
to CAA section 112. Specifically, if an owner or operator is not
currently required to get a major NSR or title V permit for oil and gas
sources, including well completions, it would not be required to get a
major NSR or title V permit as a result of these proposed standards.
EPA-approved state and local major source permitting programs would not
be affected. That is, state and local agencies with EPA-approved
programs will still make case-by-case major source determinations for
purposes of major NSR and title V, relying on the regulatory criteria,
as explained in the McCarthy Memo.\6\ Consistent with the McCarthy
Memo, whether or not a permitting authority should aggregate two or
more pollutant-emitting activities into a single major stationary
source for purposes of NSR and title V remains a case-by-case decision
in which permitting authorities retain the discretion to consider the
factors relevant to the specific circumstances of the permitted
activities.
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\6\ Withdrawal of Source Determinations for Oil and Gas
Industries, September 22, 2009. This memo continues to articulate
the Agency's interpretation for major NSR and title V permitting of
oil and gas sources.
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In addition, the proposed standards would not change the
requirements for determining whether oil and gas sources are subject to
minor NSR. Nor would the proposed standards affect existing EPA-
approved state and local minor NSR rules, as well as policies and
practices implementing those rules. Many state and local agencies have
already adopted minor NSR permitting programs that provide for control
of emissions from relatively small emission sources, including various
pieces of equipment used in oil and gas fields. State and local
agencies would be able to continue to use any EPA-approved General
Permits, Permits by Rule, and other similar streamlining mechanisms to
permit oil and gas sources such as wells. We recently promulgated the
final Tribal Minor NSR rules for use in issuing minor issue permits on
tribal lands, where many oil and gas sources are located.
The proposed standards will lead to better control of and reduced
emissions from oil and gas production, gas processing and transmission
and storage, including wells. In some instances, we anticipate that
complying with the NSPS would reduce emissions from these smaller
sources to below the minor source applicability thresholds. In those
cases, sources that would otherwise have been subject to minor NSR
would not need to get minor NSR permits as a result of being subject to
the NSPS. Accordingly, the number of minor NSR permits, as well as the
Agency resources needed to issue them, would be reduced.
We expect the emission reductions achieved from the proposed
standards to significantly improve ozone nonattainment problems in
areas where oil and gas production occurs. Strategies for attaining and
maintaining the national ambient air quality standards (NAAQS) are a
function of SIP (or, in some instances, Federal Implementation Plans
and Tribal Implementation Plans) pursuant to CAA section 110. In
developing plans to attain and maintain the NAAQS, EPA works with
state, local or Tribal agencies to account for growth and develop
overall control strategies that address existing and expected
emissions. The reductions achieved by the standards will make it easier
for state and local agencies to plan for and to attain and maintain the
ozone NAAQS.
2. How does this action affect applicability of CAA title V?
Under section 502(a) of the CAA, the EPA may exempt one or more
non-major sources \7\ subject to CAA section 111 (NSPS) standards from
the requirements of title V if the EPA finds that compliance with such
requirements is ``impracticable, infeasible, or unnecessarily
burdensome'' on such sources. The EPA determine whether to exempt a
non-major source from title V at the time we issue the relevant CAA
section 111 standards (40 CFR 70.3(b)(2)). We are proposing in this
action to exempt from the requirements of title V non-major sources
that would be subject to the proposed NSPS for well completions,
pneumatic devices, compressors, and/or storage vessels. These non-major
sources (hereinafter referred to as the ``oil and gas NSPS non-major
sources'') would not be required to obtain title V permits solely as a
result of being subject to one or more of the proposed NSPS identified
above (hereinafter referred to as the ``proposed NSPS''); however, if
they were otherwise required to obtain title V permits, such
requirement(s) would not be affected by the proposed exemption.
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\7\ CAA section 502(a) prohibits title V exemption for any major
source, which is defined in CAA section 501(2) and 40 CFR 70.2.
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Consistent with the statute, the EPA believes that compliance with
title V permitting is ``unnecessarily burdensome'' for the oil and gas
NSPS non-major sources. The EPA's inquiry into whether this criterion
was satisfied is based primarily upon consideration of the following
four factors: (1) Whether title V would result in significant
improvements to the compliance requirements that we are proposing for
the oil and gas NSPS affected non-major sources; (2) whether title V
permitting would impose a significant burden on these non-major sources
and whether that burden would be aggravated by any difficulty these
sources may have in obtaining assistance from permitting agencies; (3)
whether the costs of title V permitting for these non-major sources
would be justified, taking into consideration any potential gains in
compliance likely to occur for such sources; and (4) whether there are
implementation and enforcement programs in place that are sufficient to
assure compliance with the proposed Oil and Natural Gas NSPS without
relying on title V permits. Not all of the four factors must weigh in
favor of an exemption. See 70 FR 75320, 75323 (Title V Exemption Rule).
Instead, the factors are to be considered in combination and the EPA
determines whether the factors, taken together, support an exemption
from title V for the oil and gas non-major sources. Additionally,
consistent with the guidance provided by the legislative history of CAA
section 502(a),\8\ we considered whether exempting the Oil and Natural
Gas NSPS non-major sources would adversely affect public health,
welfare or the environment. The first factor is whether title V would
result in significant improvements to the compliance requirements in
the proposed NSPS. A finding that title V would not result in
significant improvements to the compliance requirements in the proposed
NSPS would support a conclusion that title V permitting is
``unnecessary'' for non-
[[Page 52752]]
major sources subject to the Oil and Natural Gas Production NSPS.
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\8\ The legislative history of section 502(a) suggests that EPA
should not grant title V exemptions where doing so would adversely
affect public health, welfare or the environment. (See Chafee-Baucus
Statement of Senate Managers, Environment and Natural Resources
Policy Division 1990 CAA Leg. Hist. 905, Compiled November 1993.)
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One way that title V may improve compliance is by requiring
monitoring (including recordkeeping designed to serve as monitoring) to
assure compliance with permit terms and conditions reflecting the
emission limitations and control technology requirements imposed in the
standard. See 40 CFR 70.6(c)(1) and 40 CFR 71.6(c)(1). The ``periodic
monitoring'' provisions of 40 CFR 70.6(a)(3)(i)(B) and 40 CFR
71.6(a)(3)(i)(B) require new monitoring to be added to the permit when
the underlying standard does not already require ``periodic testing or
instrumental or noninstrumental monitoring (which may consist of
recordkeeping designed to serve as monitoring).'' In addition, title V
imposes a number of recordkeeping and reporting requirements that may
be important for assuring compliance. These include requirements for a
monitoring report at least every 6 months, prompt reports of
deviations, and an annual compliance certification. See 40 CFR
70.6(a)(3) and 40 CFR 71.6(a)(3), 40 CFR 70.6(c)(1) and 40 CFR
71.6(c)(1), and 40 CFR 70.6(c)(5) and 40 CFR 71.6(c)(5). To determine
whether title V permits would add significant compliance requirements
to the proposed NSPS, we compared the title V monitoring, recordkeeping
and reporting requirements mentioned above to those requirements
proposed for the Oil and Natural Gas NSPS affected facilities.
For wellhead affected facilities (well completions), the proposed
NSPS would require (1) 30-day advance notification of each well
completion to be performed; (2) noninstrumental monitoring, which is
achieved through documentation and recordkeeping of procedures followed
during each completion, including total duration of the completion
event, amount of time gas is recovered using reduced emission
completion techniques, amount of time gas is combusted, amount of time
gas is vented to the atmosphere and justification for periods when gas
is combusted or vented rather than being recovered; (3) reports of
cases where well completions were not performed in compliance with the
NSPS; (4) annual reports that document all completions performed during
the reporting period (a single report may be used to document multiple
completions conducted by a single owner or operator during the
reporting period); and (5) annual compliance certifications submitted
with the annual report.
These monitoring, recordkeeping and reporting requirements in the
proposed NSPS for well completions are sufficient to ensure that the
Administrator, the state, local and tribal agencies and the public are
aware of completion events before they are performed to provide
opportunity for inspection. Sufficient documentation would also be
required to be retained and reported to the Administrator to assure
compliance with the NSPS for well completions. In light of the above,
we have determined that additional monitoring through title V is not
needed and that the monitoring, recordkeeping and reporting
requirements described above are sufficient to assure compliance with
the proposed requirements for well completions.
With respect to storage vessels, the proposed NSPS would require
95-percent control of VOC emissions. The proposed standard could be met
by a vapor recovery unit, a flare control device or other control
device. The proposed NSPS would require an initial performance test
followed by continuous monitoring of the control device used to meet
the 95-percent control. We believe that the monitoring requirements
described above are sufficient to assure compliance with the proposed
NSPS for storage vessels and, therefore, additional monitoring through
title V is not needed. In addition to monitoring, as part of the first
factor, we have considered the extent to which title V could
potentially enhance compliance through recordkeeping or reporting
requirements. The proposed NSPS would require (1) construction, startup
and modification notifications, as required by 40 CFR 60.7(a); and (2)
annual reports that identify all storage vessel affected facilities of
the owner or operator and documentation of periods of non-compliance.
The proposed NSPS would also require records documenting liquid
throughput of condensate or crude oil (to determine applicability), as
provided for in the proposed rule. Recordkeeping would also include
records of the initial performance test and other information that
document compliance with applicable emission limit. These requirements
are similar to those under title V. In light of the above, we believe
that the monitoring, recordkeeping and reporting requirements described
above are sufficient to assure compliance with the proposed NSPS for
storage vessels.
For pneumatic controllers, centrifugal compressors and
reciprocating compressors, the proposed NSPS are in the form of
operational, work practice or equipment standards.\9\ For each of these
affected facilities, the proposed NSPS would require: (1) Construction,
startup and modification notifications, as required by 40 CFR 60.7(a);
(2) annual reports; (3) for each pneumatic controller installed or
modified (including replacement of an existing controller), records of
location and date of installation and documentation that each
controller emits no more than the applicable emission limit or is
exempt (with rationale for the exemption); (4) for each centrifugal
compressor, records that document that each new or modified compressor
is equipped with dry seals; and (5) for each new or modified
reciprocating compressor, records of rod packing replacement, including
elapsed operating hours since the previous rod packing installation.
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\9\ The proposed numeric standards for pneumatic controllers
reflect the use of specific equipment (either non-gas driven device
or low-bleed device).
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For these other affected sources described above, the proposed NSPS
provide monitoring in the form of recordkeeping (as described above)
that would assure compliance with the proposed operational, work
practice or equipment standards. Monitoring by means other than
recordkeeping would not be practical or appropriate for these
standards. Records are required to ensure that these standards and
practices are followed. We believe that the monitoring, recordkeeping
and reporting requirements described above are sufficient to assure
compliance with the proposed NSPS for pneumatic controllers and
compressors.
We acknowledge that title V might provide for additional compliance
requirements for these non-major sources, but we have determined, as
explained above, that the monitoring, recordkeeping and reporting
requirements in this proposed NSPS are sufficient to assure compliance
with the proposed standards for well completions, storage vessels,
pneumatic controllers and compressors. Further, given the nature of
some of the operations and the types of the requirements at issue, the
additional compliance requirements under title V would not
significantly improve the compliance requirements in this proposed
NSPS. For instance, well completions occur over a very short period
(generally 3 to 10 days), and the proposed NSPS for pneumatic
controllers and centrifugal compressors can be met by simply installing
the equipment that meet the proposed emission limit; therefore, the
semi-annual reporting requirement under title V would not improve
compliance with
[[Page 52753]]
these proposed NSPS and, in fact, may seem inappropriate for such short
term operations.
For the reasons stated above, we believe that title V would not
result in significant improvements to the compliance requirements that
are provided in this proposed NSPS. Therefore, the first factor
supports a conclusion that title V permitting is ``unnecessary'' for
non-major sources subject to the Oil and Natural Gas NSPS.
The second factor we considered is whether title V permitting would
impose significant burdens on the oil and natural gas NSPS non-major
sources and whether that burden would be aggravated by any difficulty
these sources may have in obtaining assistance from permitting
agencies. Subjecting any source to title V permitting imposes certain
burdens and costs that do not exist outside of the title V program. EPA
estimated that the average cost of obtaining and complying with a title
V permit was $65,700 per source for a 5-year permit period, including
fees. See Information Collection Request (ICR) for Part 70 Operating
Permit Regulations, January 2007, EPA ICR Number 1587.07. EPA does not
have specific estimates for the burdens and costs of permitting the oil
and gas NSPS non-major sources; however, there are certain activities
associated with the 40 CFR part 70 and 40 CFR part 71 rules. These
activities are mandatory and impose burdens on any facility subject to
title V. They include reading and understanding permit program
regulations; obtaining and understanding permit application forms;
answering follow-up questions from permitting authorities after the
application is submitted; reviewing and understanding the permit;
collecting records; preparing and submitting monitoring reports;
preparing and submitting prompt deviation reports, as defined by the
state, which may include a combination of written, verbal and other
communication methods; collecting information, preparing and submitting
the annual compliance certification; preparing applications for permit
revisions every 5 years; and, as needed, preparing and submitting
applications for permit revisions. In addition, although not required
by the permit rules, many sources obtain the contractual services of
consultants to help them understand and meet the permitting program's
requirements. The ICR for 40 CFR part 70 provides additional
information on the overall burdens and costs, as well as the relative
burdens of each activity described here. Also, for a more comprehensive
list of requirements imposed on 40 CFR part 70 sources (hence, burden
on sources), see the requirements of 40 CFR 70.3, 40 CFR 70.5, 40 CFR
70.6, and 40 CFR 70.7. The activities described above, which are quite
extensive and time consuming, would be a significant burden on the non-
major sources that would be subject to the proposed NSPS, in particular
for well completion and/or pneumatic devices, considering the short
duration of a well completion and the one time equipment installation
of a pneumatic controller for meeting the proposed NSPS. Furthermore,
some of the non-major sources that would be subject to the proposed
NSPS may be small entities that may lack the technical resources and,
therefore, need assistance from the permitting authorities to comply
with the title V permitting requirements. Based on our projections,
over 20,000 well completions (for both new hydraulically fractured gas
wells and for existing gas wells that are subsequently fractured or re-
fractured) will be performed each year. For pneumatic controller
affected facilities, we estimate that approximately 14,000 new
controllers would be subject to the NSPS each year. Our estimated
numbers of affected facilities that would be subject to the proposed
NSPS for storage vessels and compressors are smaller (around 500
compressors and 300 storage vessels). Although we do not know the total
number of non-major sources that would be subject to the proposed NSPS,
based on the estimated numbers of affected facilities, we anticipate a
significant increase in the number of permit applications that
permitting authorities would have to process each year. This
significant burden on the permitting authorities raises a concern with
the potential difficulty or delay that the small entities may face in
obtaining sufficient assistance from the permitting authorities.
The third factor we considered is whether the costs of title V
permitting for these area sources would be justified, taking into
consideration any potential gains in compliance likely to occur for
such sources. We concluded, in considering the first factor, that the
monitoring, recordkeeping and reporting requirements in this proposed
NSPS assure compliance with the proposed standards, that title V would
not result in significant improvement to these compliance requirements
and, that, in some instances, certain title V compliance requirements
may not be appropriate. In addition, as discussed above in our
consideration of the second factor, we have concerns with the potential
burdens that title V may impose on these sources. In addition, below in
our consideration of the fourth factor, we find that there are adequate
implementation and enforcement programs in place to assure compliance
with the proposed NSPS. In light of the above, we find that the costs
of title V permitting are not justified for the sources we propose to
exempt. Accordingly, the third factor supports title V exemption for
the oil and gas NSPS non-major sources.
The fourth factor we considered is whether there are implementation
and enforcement programs in place that are sufficient to assure
compliance with the proposed NSPS for oil and gas sources without
relying on title V permits. The CAA provides States the opportunity to
take delegation of NSPS. Before the EPA will delegate the program, the
EPA will evaluate the state programs to ensure that states have
adequate capability to enforce the CAA section 111 regulations and
provide assurances that they will enforce the NSPS. In addition, EPA
retains authority to enforce this NSPS anytime under CAA sections 111,
113 and 114. Accordingly, we can enforce the monitoring, recordkeeping
and reporting requirements, which, as discussed under the first factor,
are adequate to assure compliance with this NSPS. Also, states and the
EPA often conduct voluntary compliance assistance, outreach and
education programs (compliance assistance programs), which are not
required by statute. We determined that these additional programs will
supplement and enhance the success of compliance with these proposed
standards. We believe that the statutory requirements for
implementation and enforcement of this NSPS by the delegated states,
the EPA and the additional assistance programs described above together
are sufficient to assure compliance with these proposed standards
without relying on title V permitting.
Our balance of the four factors strongly supports a finding that
title V is unnecessarily burdensome for the oil and gas non-major
sources. While title V might add additional compliance requirements if
imposed, we believe that there would not be significant improvements to
the compliance requirements in this proposed rule because the proposed
rule requirements are specifically designed to assure compliance with
the proposed NSPS and, as explained above, some of the title V
requirements may not be appropriate for certain operations and/or
proposed standards. We are also concerned with the potential burden
that title V may impose on some of these
[[Page 52754]]
sources. In light of little or no potential gain in compliance if title
V were required, we do not believe that the costs of title V permitting
is justified in this case. Finally, there are adequate implementation
and enforcement programs in place to assure compliance with these
proposed standards. Thus, we propose that title V permitting is
``unnecessarily burdensome'' for the oil and gas non-major sources.
In addition to evaluating whether compliance with title V
requirements is ``unnecessarily burdensome,'' EPA also considered,
consistent with guidance provided by the legislative history of section
502(a), whether exempting oil and gas NSPS non-major sources from title
V requirements would adversely affect public health, welfare or the
environment. The title V permit program does not impose new substantive
air quality control requirements on sources, but instead requires that
certain procedural measures be followed, particularly with respect to
determining compliance with applicable requirements. As stated in our
consideration of factor one, title V would not lead to significant
improvements in the compliance requirements for the proposed NSPS. For
the reason stated above, we believe that exempting these non-major
sources from title V permitting requirements would not adversely affect
public health, welfare or the environment.
On the contrary, we are concerned that requiring title V in this
case could potentially adversely affect public health, welfare or the
environment. As mentioned above, we anticipate a significant increase
in the number of permit applications that permitting authorities would
have to process each year. Depending on the number of non-major sources
that would be subject to this rule, requiring permits for those
sources, at least in the first few years of implementation, could
potentially adversely affect public health, welfare or the environment
by shifting state agencies resources away from assuring compliance for
major sources (which cannot be exempt from title V) to issuing new
permits for these non-major sources, potentially reducing overall air
program effectiveness.
Based on the above analysis, we conclude that title V permitting
would be ``unnecessarily burdensome'' for oil and gas NSPS non-major
sources. We are, therefore, proposing that these non-major sources be
exempt from title V permitting requirements.
VI. Rationale for Proposed Action for NSPS
A. What did we evaluate relative to NSPS?
As noted above, there are two existing NSPS that address emissions
from the Oil and Natural Gas source category. These NSPS are relatively
narrow in scope, as they address emissions only at natural gas
processing plants. Specifically, 40 CFR part 60, subpart KKK addresses
VOC emissions from leaking equipment at onshore natural gas processing
plants and 40 CFR part 60, subpart LLL addresses SO2
emissions from natural gas processing plants.
CAA section 111(b)(1)(B) requires the EPA to review and revise, if
appropriate, NSPS standards. Accordingly, we evaluated whether the
existing NSPS reflect the BSER for the emission sources that they
address. This review was conducted by examining currently used, new and
emerging control systems and assessing whether they represent advances
in emission reduction techniques from those upon which the existing
NSPS are based, including advances in LDAR approaches and
SO2 control at natural gas processing plants. For each new
or emerging control option identified, we then evaluated emission
reductions, costs, energy requirements and non-air quality impacts,
such as solid waste generation.
In this package, we have also evaluated whether there were
additional pollutants emitted by facilities in the Oil and Natural Gas
source category that warrant regulation and for which we have adequate
information to promulgate standards of performance. Finally, we have
identified additional processes in the Oil and Natural Gas source
category for which it may be appropriate to develop performance
standards. This would include processes that emit the currently
regulated pollutants, VOC and SO2, as well as any additional
pollutants for which we determined regulation to be appropriate.
B. What are the results of our evaluations and proposed actions
relative to NSPS?
1. Do the existing NSPS reflect the BSER for sources covered?
Consistent with our obligations under CAA section 111(b), we
evaluated whether the control options reflected in the current NSPS for
the Oil and Natural Gas source category still represent BSER. To
evaluate the BSER options for equipment leaks, we reviewed EPA's
current LDAR programs, the Reasonably Available Control Technology
(RACT)/Best Available Control Technology (BACT)/Lowest Achievable
Emission Rate (LAER) Clearinghouse (RBLC) database, and emerging
technologies that have been identified by partners in the Natural Gas
STAR program.
The current NSPS for equipment leaks of VOC at natural gas
processing plants (40 CFR part 60, subpart KKK) requires compliance
with specific provisions of 40 CFR part 60, subpart VV, which is a LDAR
program, based on the use of EPA Method 21 to identify equipment leaks.
In addition to the subpart VV requirements, we reviewed the LDAR
requirements in 40 CFR part 60, subpart VVa. This LDAR program is
considered to be more stringent than the subpart VV requirements,
because it has lower component leak threshold definitions and more
frequent monitoring, in comparison to the subpart VV program.
Furthermore, subpart VVa requires monitoring of connectors, while
subpart VV does not. We also reviewed options based on optical gas
imaging.
As mentioned above, the currently required LDAR program for natural
gas processing plants (40 CFR part 60, subpart KKK) is based on EPA
Method 21, which requires the use of an organic vapor analyzer to
monitor components and to measure the concentration of the emissions in
identifying leaks. We recognize that there have been advancements in
the use of optical gas imaging to detect leaks from these same types of
components. These instruments do not yet provide a direct measure of
leak concentrations. The instruments instead provide a measure of a
leak relative to an instrument specific calibration point. Since the
promulgation of 40 CFR part 60, subpart KKK (which requires Method 21
leak measurement monthly), the EPA has updated the 40 CFR part 60
General Provisions to allow the use of advanced leak detection tools,
such as optical gas imaging and ultrasound equipment as an alternative
to the LDAR protocol based on Method 21 leak measurements (see 40 CFR
60.18(g)). The alternative work practice allowing use of these advanced
technologies includes a provision for conducting a Method 21-based LDAR
check of the regulated equipment annually to verify good performance.
In our review, we evaluated 4 options in considering BSER for VOC
equipment leaks at natural gas processing plants. One option we
evaluated consists of changing from a 40 CFR part 60, subpart VV-level
program, which is what 40 CFR part 60, subpart KKK currently requires,
to a 40 CFR part 60, subpart VVa program, which applies to new
[[Page 52755]]
synthetic organic chemical plants after 2006. Subpart VVa lowers the
leak definition for valves from 10,000 parts per million (ppm) to 500
ppm, and requires the monitoring of connectors. In our analysis of
these impacts, we estimated that, for a typical natural gas processing
plant, the incremental cost effectiveness of changing from the current
subpart VV-level program to a subpart VVa-level program using Method 21
is $3,352 per ton of VOC reduction.
In evaluating 40 CFR part 60, subpart VVa-level LDAR at processing
plants, we also analyzed separately the individual types of components
(valves, connectors, pressure relief devices and open-ended lines) to
determine cost effectiveness for individual components. Detailed
discussions of these component-by-component analyses are included in
the TSD in the docket. Cost effectiveness ranged from $144 per ton of
VOC (for valves) to $4,360 per ton of VOC (for connectors), with no
change in requirements for pressure relief devices and open-ended
lines.
Another option we evaluated for gas processing plants was the use
of optical gas imaging combined with an annual EPA Method 21 check
(i.e., the alternative work practice for monitoring equipment for leaks
at 40 CFR 60.18(g)). We had previously determined that the VOC
reduction achieved by this combination of optical gas imaging and
Method 21 would be equivalent to reductions achieved by the 40 CFR part
60, subpart VVa-level program. Based on that emission reduction level,
we determined the cost effectiveness of this option to be $6,462 per
ton of VOC reduction. This analysis is based on the facility purchasing
an optical gas imaging system costing $85,000. However, we identified
at least one manufacturer who rents the optical gas imaging systems.
That manufacturer rents the optical gas imaging system for $3,950 per
week. Using this rental cost in place of the purchase cost, the VOC
cost effectiveness of the monthly optical gas imaging combined with
annual Method 21 checks is $4,638 per ton of VOC reduction.\10\ A third
option we evaluated consisted of monthly optical gas imaging without an
annual Method 21 check. We estimated the annual cost of the monthly
optical gas imaging LDAR program to be $76,581, based on camera
purchase, or $51,999, based on camera rental. However, because we were
unable to estimate the VOC emissions achieved by an optical imaging
program alone, we were unable to estimate the cost effectiveness of
this option.
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\10\ Because optical gas imaging is used to view several pieces
of equipment at a facility at once to survey for leaks, options
involving imaging are not amenable to a component by component
analysis.
---------------------------------------------------------------------------
Finally, we evaluated a fourth option similar to the third option,
except that the optical gas imaging would be performed annually rather
than monthly. For this option, we estimated the annual cost to be
$43,851, based on camera purchase, or $18,479, based on camera rental.
We request comment on the applicability of an LDAR program based
solely on the use of optical gas imaging. Of most use to us would be
information on the effectiveness of this and, potentially, other
advanced measurement technologies, to detect and repair small leaks on
the same order or smaller than specified in the 40 CFR part 60, subpart
VVa equipment leak requirements and the effects of increased frequency
of and associated leak detection, recording and repair practices.
Because we could not estimate the cost effectiveness of options 3
and 4, we could not identify either of these two options as BSER for
reducing VOC leaks at gas processing plants. Because options 1 and 2
have achieved equivalent VOC reduction and are both cost effective, we
believe that both options 1 and 2 reflect BSER for LDAR for natural gas
processing plants. As mentioned above, option 1 is the LDAR in 40 CFR
part 60, subpart VVa and option 2 is the alternative work practice at
40 CFR 60.18(g) and is already available to use as an alternative to
subpart VVa LDAR. Therefore, we propose that the NSPS for equipment
leaks of VOC at gas processing plants be revised to require compliance
with the subpart VVa equipment leak requirements.
For 40 CFR part 60, subpart LLL, we reviewed control systems for
SO2 emissions from sweetening units located at natural gas
processing plants, including those followed by a sulfur recovery unit.
Subpart LLL provides specific standards for SO2 emission
reduction efficiency, on the basis of sulfur feed rate and the sulfur
content of the natural gas.
According to available literature, the most widely used process for
converting H2S in acid gases (i.e., H2S and
CO2) separated from natural gas by a sweetening process
(such as amine treating) into elemental sulfur is the Claus process.
Sulfur recovery efficiencies are higher with higher concentrations of
H2S in the feed stream due to the thermodynamic equilibrium
limitation of the Claus process. The Claus sulfur recovery unit
produces elemental sulfur from H2S in a series of catalytic
stages, recovering up to 97-percent recovery of the sulfur from the
acid gas from the sweetening process. Further, sulfur recovery is
accomplished by making process modifications or by employing a tail gas
treatment process to convert the unconverted sulfur compounds from the
Claus unit.
We evaluated process modifications and tail gas treatment options
when we proposed 40 CFR part 60, subpart LLL. 49 FR 2656, 2659-2660
(1984). As we explained in the preamble to the proposed subpart LLL,
control through sulfur recovery with tail gas treatment may not always
be cost effective, depending on sulfur feed rate and inlet
H2S concentrations. Therefore, other methods of increasing
sulfur recovery via process modifications were evaluated. As shown in
the original evaluation, the performance capabilities and costs of each
of these technologies are highly dependent on the ratio of
H2S and CO2 in the gas stream and the total
quantity of sulfur in the gas stream being treated. The most effective
means of control was selected as BSER for the different stream
characteristics. As a result, separate emissions limitations were
developed in the form of equations that calculate the required initial
and continuous emission reduction efficiency for each plant. The
equations were based on the design performance capabilities of the
technologies selected as BSER relative to the gas stream
characteristics. 49 FR 2656, 2663-2664 (1984). The emission limit for
sulfur feed rates at or below 5 long tons per day, regardless of
H2S content, was 79 percent. For facilities with sulfur feed
rates above 5 long tons per day, the emission limits ranged from 79
percent at an H2S content below 10 percent to 99.8 percent
for H2S contents at or above 50 percent.
To review these emission limitations, we performed a search of the
RBLC database and state regulations. No state regulations identified
had emission limitations more stringent than 40 CFR part 60, subpart
LLL. However, the RBLC database search identified two entries with
SO2 emission reductions of 99.9 percent. One entry is for a
facility in Bakersfield, California, with a 90 long ton per day sulfur
recovery unit followed by an amine-based tail-gas treating unit. The
second entry is for a facility in Coden, Alabama, with a sulfur
recovery unit with a sulfur feed rate of 280 long tons per day,
followed by selective catalytic reduction and a tail gas incinerator.
However, neither of these entries contained information regarding the
H2S contents of the feed
[[Page 52756]]
stream. Because the sulfur recovery efficiency of these large sized
plants was greater than 99.8 percent, we reevaluated the original data.
Based on the available cost information, it appears that a 99.9-percent
efficiency is cost effective for facilities with a sulfur feed rate
greater than 5 long tons per day and H2S content equal to or
greater than 50 percent. Based on our review, we are proposing that the
maximum initial and continuous efficiency for facilities with a sulfur
feed rate greater than 5 long tons per day and an H2S
content equal to or greater than 50 percent be raised to 99.9 percent.
We are not proposing to make changes to the equations.
Our search of the RBLC database did not uncover information
regarding costs and achievable emission reductions to suggest that the
emission limitations for facilities with a sulfur feed rate less than 5
long tons per day or H2S content less than 50 percent should
be modified. Therefore, we are not proposing any changes to the
emissions limitations for facilities with sulfur feed rate and
H2S content less than 5 long tons per day and 50 percent,
respectively.
2. What pollutants are being evaluated in this Oil and Natural Gas NSPS
package?
The two current NSPS for the Oil and Natural Gas source category
address emissions of VOC and SO2. In addition to these
pollutants, sources in this source category also emit a variety of
other pollutants, most notably, air toxics. As discussed elsewhere in
this notice, there are NESHAP that address air toxics from the oil and
natural gas sector.
In addition, processes in the Oil and Natural Gas source category
emit significant amounts of methane. The 1990-2009 U.S. GHG Inventory
estimates 2009 methane emissions from Petroleum and Natural Gas Systems
(not including petroleum refineries) to be 251.55 MMtCO2e
(million metric tons of CO2-equivalents
(CO2e)).\11\ The emissions estimated from well completions
and recompletions exclude a significant number of wells completed in
tight sand plays, such as the Marcellus, due to availability of data
when the 2009 Inventory was developed. The estimate in this proposal
includes an adjustment for tight sand plays (being considered as a
planned improvement in development of the 2010 Inventory). This
adjustment would increase the 2009 Inventory estimate by 76.74
MMtCO2e. The total methane emissions from Petroleum and
Natural Gas Systems, based on the 2009 Inventory, adjusted for tight
sand plays and the Marcellus, is 328.29 MMtCO2e. Although
this proposed rule does not include standards for regulating the GHG
emissions discussed above, we continue to assess these significant
emissions and evaluate appropriate actions for addressing these
concerns. Because many of the proposed requirements for control of VOC
emissions also control methane emissions as a co-benefit, the proposed
VOC standards would also achieve significant reduction of methane
emissions.
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\11\ U.S. EPA. Inventory of U.S. Greenhouse Gas Inventory and
Sinks. 1990-2009. http://www.epa.gov/climatechange/emissions/downloads10/US-GHG-Inventory-2010_ExecutiveSummary.pdf.
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Significant emissions of oxides of nitrogen (NOX) also
occur at oil and natural gas sites due to the combustion of natural gas
in reciprocating engines and combustion turbines used to drive the
compressors that move natural gas through the system, and from
combustion of natural gas in heaters and boilers. While these engines,
turbines, heaters and boilers are co-located with processes in the oil
and natural gas sector, they are not in the Oil and Natural Gas source
category and are not being addressed in this action. The NOX
emissions from engines and turbines are covered by the Standards of
Performance for Stationary Spark Internal Combustion Engines (40 CFR
part 60, subpart JJJJ) and Standards of Performance for Stationary
Combustion Turbines (40 CFR part 60, subpart KKKK), respectively.
An additional source of NOX emissions would be pit
flaring of VOC emissions from well completions during periods where REC
is not feasible, as would be required under our proposed operational
standards for wellhead affected facilities. As discussed below in
section VI.B.4 (well completion), pit flaring is the only way we
identified of controlling VOC emissions during these periods. Because
there is no way of directly measuring the NOX produced, nor
is there any way of applying controls other than minimizing flaring, we
propose to allow flaring only when REC is not feasible. We have
included our estimates of NOX formation from pit flaring in
our discussion of secondary impacts in section VI.B.4.
3. What emission sources are being evaluated in this Oil and Natural
Gas NSPS package?
The current NSPS only cover emissions of VOC and SO2
from one type of facility in the oil and natural gas sector, which is
the natural gas processing plant. This is the only type of facility in
the Oil and Natural Gas source category where we would expect
SO2 to be emitted directly, although H2S
contained in sour gas, when oxidized in the atmosphere or combusted in
boilers and heaters in the field, forms SO2 as a product of
oxidation. These field boilers and heaters are not part of the Oil and
Natural Gas source category and are generally too small to be regulated
by the NSPS covering boilers (i.e., they have a heat input of less than
10 million British Thermal Units per hour). However, we may consider
addressing them as part of a future sector-based strategy for the oil
and natural gas sector.
In addition to VOC emissions from gas processing plants, there are
numerous sources of VOC throughout the oil and natural gas sector that
are not addressed by the current NSPS. As explained above in section
V.A, pursuant to CAA section 111(b), to the extent necessary, we are
modifying the listed category to include all segments of the oil and
natural gas industry for regulation. We are also proposing VOC
standards to cover additional processes at oil and natural gas
operations. These include NSPS for VOC from gas well completions,
pneumatic controllers, compressors and storage vessels.
We believe that produced water ponds are also a potentially
significant source of emissions, but we have only limited information.
We, therefore, solicit comments on produced water ponds, particularly
in the following subject areas:
(a) We are requesting comments pertaining to methods for
calculating emissions. The State of Colorado currently uses a mass
balance that assumes 100 percent of the VOC content is emitted to the
atmosphere. Water9, an air emissions model, is another option that has
some limitations, including poor methanol estimation.
(b) We are requesting additional information on typical VOC content
in produced water and any available chemical analyses, including data
that could help clarify seasonal variations or differences among gas
fields. Additionally, we request data that increase our understanding
of how changing process variables or age of wells affect produced water
output and VOC content.
(c) We solicit information on the size and throughput capacity of
typical evaporation pond facilities and request suggestions on
parameters that could be used to define affected facilities or affected
sources. We also seek information on impacts of smaller evaporation
pits that are co-located with drilling operations, whether those
[[Page 52757]]
warrant control and, if so, how controls should be developed.
(d) An important factor is cost of emission reduction technologies,
including recovery credits or cost savings realized from recovered
salable product. We are seeking information on these considerations as
well.
(e) We are also seeking information on any limitations for emission
reduction technologies such as availability of electricity, waste
generation and disposal and throughput and concentration constraints.
(f) Finally, we solicit information on separator technologies that
are able to improve the oil-water separation efficiency.
4. What are the rationales for the proposed NSPS?
We have provided below our rationales for the proposed BSER
determinations and performance standards for a number of VOC emission
sources in the Oil and Natural Gas source category that are not covered
by the existing NSPS. Our general process for evaluating systems of
emission reduction for the emission sources discussed below included:
(1) Identification of available control measures; (2) evaluation of
these measures to determine emission reductions achieved, associated
costs, nonair environmental impacts, energy impacts and any limitations
to their application; and (3) selection of the control techniques that
represent BSER based on the information we considered.
We identified the control options discussed in this package through
our review of relevant state and local requirements and mitigation
measures developed and reported by the EPA's Natural Gas STAR program.
The EPA's Natural Gas STAR program has worked with industry partners
since 1993 to identify cost effective measures to reduce emissions of
methane and other pollutants from natural gas operations. We relied
heavily on this wealth of information in conducting this review. We
also identified state regulations, primarily in Colorado and Wyoming,
which require mitigation measures for some emission sources in the Oil
and Natural Gas source category.
a. NSPS for Well Completions
Well completion activities are a significant source of VOC
emissions, which occur when natural gas and non-methane hydrocarbons
are vented to the atmosphere during flowback of a hydraulically
fractured gas well. Flowback emissions are short-term in nature and
occur over a period of several days following fracturing of a new well
or refracturing of an existing well. Well completions include multiple
steps after the well bore hole has reached the target depth. These
steps include inserting and cementing-in well casing, perforating the
casing at one or more producing horizons, and often hydraulically
fracturing one or more zones in the reservoir to stimulate production.
Well recompletions may also include hydraulic fracturing. Hydraulic
fracturing is one technique for improving gas production where the
reservoir rock is fractured with very high pressure fluid, typically
water emulsion with a proppant (generally sand) that ``props open'' the
fractures after fluid pressure is reduced. Emissions are a result of
the backflow of the fracture fluids and reservoir gas at high volume
and velocity necessary to lift excess proppant and fluids to the
surface. This multi-phase mixture is often directed to a surface
impoundment where natural gas and VOC vapors escape to the atmosphere
during the collection of water, sand and hydrocarbon liquids. As the
fracture fluids are depleted, the backflow eventually contains more
volume of natural gas from the formation. Wells that are fractured
generally have great amounts of emissions because of the extended
length of the flowback period required to purge the well of the fluids
and sand that are associated with the fracturing operation. Along with
the fluids and sand from the fracturing operation, the 3- to 10-day
flowback period also results in emissions of natural gas and VOC that
would not occur in large quantities at oil wells or at natural gas
wells that are not fractured. Thus, we estimate that gas well
completions involving hydraulic fracturing vent substantially more VOC,
approximately 200 times more, than completions not involving hydraulic
fracturing. Specifically, we estimate that uncontrolled well completion
emissions for a hydraulically fractured gas well are approximately 23
tons of VOC, where emissions for a conventional gas well completion are
around 0.12 tons VOC. These estimates are explained in detail in the
TSD available in the docket. Based on our review, we believe that
emissions from recompletions of previously completed wells that are
fractured or refractured to stimulate production or to begin production
from a new production horizon are of similar magnitude and composition
as emissions from completions of new wells that have been hydraulically
fractured.
EPA has based the NSPS impacts analysis on best available emission
data. However, we recognize that there is uncertainty associated with
our estimates. For both new completions and recompletions, there are a
variety of factors that will determine the length of the flowback
period and actual volume of emissions such as the number of zones,
depth, pressure of the reservoir, gas composition, etc. This
variability means there will be some wells which emit more than the
estimated emission factor and some wells that emit less.
During our review, we examined information from the Natural Gas
STAR program and the Colorado and Wyoming state rules covering well
completions. We identified two subcategories of fractured gas wells:
(1) Non-exploratory and non-delineation wells; and (2) exploratory and
delineation wells. An exploratory well is the first well drilled to
determine the presence of a producing reservoir and the well's
commercial viability. A delineation well is a well drilled to determine
the boundary of a field or producing reservoir. Because exploratory and
delineation wells are generally isolated from existing producing wells,
there are no gathering lines available for collection of gas recovered
during completion operations. In contrast, non-exploratory and non-
delineation wells are located where existing, producing wells are
connected to gathering lines and are, therefore, able to be connected
to a gathering line to collect recovered salable natural gas product
that would otherwise be vented to the atmosphere or combusted.
For subcategory 1, we identified ``green'' completion, which we
refer to as REC, as an option for reducing VOC emissions during well
completions. REC are performed by separating the flowback water, sand,
hydrocarbon condensate and natural gas to reduce the portion of natural
gas and VOC vented to the atmosphere, while maximizing recovery of
salable natural gas and VOC condensate. In some cases, for a portion of
the completion operation, such as when CO2 or nitrogen is
injected with the fracture water, initial gas produced is not of
suitable quality to introduce into the gathering line due to
CO2 or nitrogen content or other undesirable characteristic.
In such cases, for a portion of the flowback period, gas cannot be
recovered, but must be either vented or combusted. In practice, REC are
often combined with combustion to minimize the amount of gas and
condensate being vented. This combustion process is rather crude,
consisting of a horizontal pipe
[[Page 52758]]
downstream of the REC equipment, fitted with a continuous ignition
source and discharging over a pit near the wellhead. Because of the
nature of the flowback (i.e., with periods of water, condensate, and
gas in slug flow), conveying the entire portion of this stream to a
traditional flare control device or other control device, such as a
vapor recovery unit, is not feasible. These control devices are not
designed to accommodate the multiphase flow consisting of water, sand
and hydrocarbon liquids, along with the gas and vapor being controlled.
Although ``pit flaring'' does not employ a traditional flare control
device, and is not capable of being tested or monitored for efficiency
due to the multiphase slug flow and intermittent nature of the
discharge of gas, water and sand over the pit, it does provide a means
of minimizing vented gas and is preferable to venting. Because of the
rather large exposed flame, open pit flaring can present a fire hazard
or other undesirable impacts in some situations (e.g., dry, windy
conditions, proximity to residences, etc.). As a result, we are aware
that owners and operators may not be able to pit flare unrecoverable
gas safely in every case. In some cases, pit flaring may be prohibited
by local ordinance.
Equipment required to conduct REC may include tankage, special gas-
liquid-sand separator traps and gas dehydration. Equipment costs
associated with REC will vary from well to well. Typical well
completions last between 3 and 10 days and costs of performing REC are
projected to be between $700 and $6,500 per day, including a cost of
approximately $3,523 per completion event for the pit flaring
equipment. However, there are savings associated with the use of REC
because the gas recovered can be incorporated into the production
stream and sold. In fact, we estimate that REC will result in an
overall net cost savings in many cases.
The emission reductions for a hydraulically fractured well are
estimated to be around 22 tons of VOC. Based on an average incremental
cost of $33,237 per completion, the cost effectiveness of REC, without
considering any cost savings, is around $1,516 per ton of VOC (which we
have previously found to be cost effective on average). When the value
of the gas recovered (approximately 150 tons of methane per completion)
is considered, the cost effectiveness is estimated as an average net
savings of $99 per ton VOC reduced, using standard discount rates. We
believe that these costs are very reasonable, given the emission
reduction that would be achieved. Aside from the potential hazards
associated with pit flaring, in some cases, we did not identify any
nonair environmental impacts, health or energy impacts associated with
REC combined with combustion. However, pit flaring would produce
NOX emissions. Because we believe that these emissions
cannot be controlled or measured directly due to the open combustion
process characteristic of pit flaring, we used published emission
factors (EPA Emission Guidelines AP-42) to estimate the NOX
emissions for purposes of assessing secondary impacts. For category 1
well completions, we estimated that 0.02 tons of NOX are
produced per event. This is based on the assumption that 5 percent of
the flowback gas is combusted by the combustion device. The 1.2 tons of
VOC controlled during the pit flaring portion of category 1 well
completions is approximately 57 times greater than the NOX
produced by pit flaring. Thus, we believe that the benefit of the VOC
reduction far outweighs the secondary impact of NOX
formation during pit flaring.
We believe that, based on the analysis above, REC in combination
with combustion is BSER for subcategory 1 wells. We considered setting
a numerical performance standard for subcategory 1 wells. However, it
is not practicable to measure the emissions during pit flaring or
venting because the gas is discharged over the pit along with water and
sand in multiphase slug flow. Therefore, we believe it is not feasible
to set a numerical performance standard. Pursuant to section 111(h)(2)
of the CAA, we are proposing an operational standard for subcategory 1
wells that would require a combination of REC and pit flaring to
minimize venting of gas and condensate vapors to the atmosphere, with
provisions for venting in lieu of pit flaring for situations in which
pit flaring would present safety hazards or for periods when the
flowback gas is noncombustible due to high concentrations of nitrogen
or CO2. The proposed operational standard would be
accompanied by requirements for documentation of the overall duration
of the completion event, duration of recovery using REC, duration of
combustion, duration of venting, and specific reasons for venting in
lieu of combustion.
We recognize that there is heterogeneity in well operations and
costs, and that while RECs may be cost-effective on average, they may
not be for all operators. Nonetheless, EPA is proposing to require an
operational standard rather than a performance-based standard (e.g.,
requiring that some percentage of emissions be flared or captured),
because we believe there are no feasible ways for operators to measure
emissions with enough certainty to demonstrate compliance with a
performance-based standard for REC in combination with pit flaring. The
EPA requests comment on this and seeks input on whether alternative
approaches to requiring REC for all operators with access to pipelines
may exist that would allow operators to meet a performance-based
standard if they can demonstrate that an REC is not cost effective.
We have discussed above certain situations where unrecoverable gas
would be vented because pit flaring would present a fire hazard or is
infeasible because gas is noncombustible due to high concentrations of
nitrogen or CO2. We solicit comment on whether there are
other such situations where flaring would be unsafe or infeasible, and
potential criteria that would support venting in lieu of pit flaring.
In addition, we learned that coalbed methane reservoirs may have low
pressure, which would present a technical barrier for performing a REC
because the well pressure may not be substantial enough to overcome
gathering line pressure. In addition, we identified that coalbed
methane wells often have low to almost no VOC emissions, even following
the hydraulic fracturing process. We solicit comment on criteria and
thresholds that could be used to exempt some well completion operations
occurring in coalbed methane reservoirs from the requirements for
subcategory 1 wells.
Of the 25,000 new and modified fractured gas wells completed each
year, we estimate that approximately 3,000 to 4,000 currently employ
reduced emission completion. We expect this number to increase to over
21,000 REC annually as operators comply with the proposed NSPS. We
estimate that approximately 9,300 new wells and 12,000 existing wells
will be fractured or refractured annually that would be subject to
subcategory 1 requirements under the NSPS. We believe that there will
be a sufficient supply of REC equipment available by the time the NSPS
becomes effective. However, energy availability could be affected if a
shortage of REC equipment was allowed to cause delays in well
completions. We request comment on whether sufficient supply of this
equipment and personnel to operate it will be available to accommodate
the increased number of REC by the effective date of the NSPS. We also
request specific estimates of
[[Page 52759]]
how much time would be required to get enough equipment in operation to
accommodate the full number of REC performed annually.
In the event that public comments indicate that available equipment
would likely be insufficient to accommodate the increase in number of
REC performed, we are considering phasing in requirements for well
completions that would achieve an overall comparable level of
environmental benefit. For example, operators performing completions of
fractured or refractured existing wells (i.e., modified wells) could be
allowed to control emissions through pit flaring instead of REC for
some period of time. After some date certain, all modified wells would
be subject to REC. We solicit comment on the phasing of requirements
for REC along with suggestions for other ways to address a potential
short-term REC equipment shortage that may hinder operators' compliance
with the proposed NSPS, while also achieving a comparable level of
reduced emissions to the air.
Although we have determined that, on average, reduced emission
completions are cost effective, well and reservoir characteristics
could vary, such that some REC are more cost effective than others.
Unlike most stationary source controls, REC equipment is used only for
a 3 to 10 day period. Our review found that most operators contract
with service companies to perform REC rather than purchase the
equipment themselves, which was reflected in our economic analysis. It
is also possible that the contracting costs of supplying and operating
REC equipment may rise in the short term with the increased demand for
those services. We request comment and any available technical
information to judge whether our assumption of $33,237 per well
completion for this service given the projected number of wells in 2015
subject to this requirement is accurate.
We believe that the proposed rule regulates only significant
emission sources for which controls are cost-effective. Nevertheless,
we solicit comment and supporting data on appropriate thresholds (e.g.,
pressure, flowrate) that we should consider in specifying which well
completions are subject to the REC requirements for subcategory 1
wells. Comments specifying thresholds should include an analysis of why
sources below these thresholds are not cost effective to control.
In addition, there may be economic, technical or other
opportunities or barriers associated with performing cost effective REC
that we have not identified in our review. For example, some small
regulated entities may have an increased source of revenue due to the
captured product. On the other hand, some small regulated entities may
have less access to REC than larger regulated entities might have. We
request information on such opportunities and barriers that we should
consider and suggestions for how we may take them into account in
structuring the NSPS.
The second subcategory of fractured gas wells includes exploratory
wells or delineation wells. Because these types of wells generally are
not in proximity to existing gathering lines, REC is not an option,
since there is no infrastructure in place to get the recovered gas to
market or further processing. For these wells, the only potential
control option we were able to identify is pit flaring, described
above. As explained above, because of the slug flow nature of the
flowback gas, water and sand, control by a traditional flare control
device or other control devices, such as vapor recovery units, is
infeasible, which leaves pit flaring as the only practicable control
system for subcategory 2 wells. As also discussed above, open pit
flaring can present a fire hazard or other undesirable impacts in some
situations. Aside from the potential hazards associated with pit
flaring, in some cases, we did not identify any nonair environmental
impacts, health or energy impacts associated with pit flaring. However,
pit flaring would produce NOX emissions. As in the case of
category 1 wells, we believe that these emissions cannot be controlled
or measured directly due to the open combustion process characteristic
of pit flaring. We again used published emission factors to estimate
the NOX emissions for purposes of assessing secondary
impacts. For category 2 well completions, we estimated that 0.32 tons
of NOX are produced as secondary emissions per completion
event. This is based on the assumption that 95 percent of flowback gas
is combusted by the combustion device. The 22 tons of VOC reduced
during the pit flaring used to control category 2 well completions is
approximately 69 times greater than the NOX produced. Thus,
we believe that the benefit of the VOC reduction far outweighs the
secondary impact of NOX formation during pit flaring.
In light of the above, we propose to determine that BSER for
subcategory 2 wells would be pit flaring. As we explained above, it is
not practicable to measure the emissions during pit flaring or venting
because the gas is discharged during flowback mixed with water and sand
in multiphase slug flow. It is, therefore, not feasible to set a
numerical performance standard.
Pursuant to CAA section 111(h)(2), we are proposing an operational
standard for subcategory 2 wells that requires minimization of venting
of gas and hydrocarbon vapors during the completion operation through
the use of pit flaring, with provisions for venting in lieu of pit
flaring for situations in which flaring would present safety hazards or
for periods when the flowback gas is noncombustible due to high
concentrations of nitrogen or carbon dioxide.
Consistent with requirements for subcategory 1 wells, owners or
operators of subcategory 2 wells would be required to document
completions and provide justification for periods when gas was vented
in lieu of combustion. We solicit comment on whether there are other
such situations where flaring would be unsafe or infeasible and
potential criteria that would support venting in lieu of pit flaring.
For controlling completion emissions at oil wells and conventional
(non-fractured) gas wells, we have identified and evaluated the
following control options: REC in conjunction with pit flaring and pit
flaring alone. Due to the low uncontrolled VOC emissions of
approximately 0.007 ton per completion and, therefore, low potential
emission reductions from these events, the cost per ton of reduction
based on REC would be extremely high (over $700,000 per ton of VOC
reduced). We evaluated the use of pit flaring alone as a system for
controlling emissions from oil wells and conventional gas wells and
determined that the cost cost-effectiveness would be approximately
$520,000 per ton for oil wells and approximately $32,000 per ton for
conventional gas wells. In light of the high cost per ton of VOC
reduction, we do not consider either of these control options to be
BSER for oil wells and conventional wells.
We propose that fracturing (or refracturing) and completion of an
existing well (i.e., a well existing prior to August 23, 2011) is
considered a modification under CAA section 111(a), because physical
change occurs to the existing well, which includes the wellbore, casing
and tubing, resulting in an emissions increase during the completion
operation. The physical change, in this case, would be caused by the
reperforation of the casing and tubing, along with the refracturing of
the wellbore. The increased VOC emissions would occur during the
flowback period following the fracturing or refracturing operation.
Therefore, the proposed
[[Page 52760]]
standards for category 1 and category 2 wells would apply to
completions at existing fractured or refractured wells.
EPA seeks comment on the 10 percent per year rate of refracturing
for natural gas wells assumed in the impacts analysis found in the TSD.
EPA has received anecdotal information suggesting that refracturing
could be occurring much less frequently, while others suggest that the
percent of wells refractured in a given year could be greater. We seek
comment and comprehensive data and information on the rate of
refracturing and key factors that influence or determine refracturing
frequency.
In addition to well completions, we considered VOC emissions
occurring at the wellhead affected facility during subsequent day-to-
day operations during well production. As discussed below in section
VI.B.1.e, VOC emissions from wellheads are very small during production
and account for about 2.6 tons VOC per year. We are not aware of any
cost effective controls that can be used to address these relatively
small emissions.
b. NSPS for Pneumatic Controllers
Pneumatic controllers are automated instruments used for
maintaining a process condition, such as liquid level, pressure,
pressure differential and temperature. Pneumatic controllers are widely
used in the oil and natural gas sector. In many situations across all
segments of the oil and gas industry, pneumatic controllers make use of
the available high-pressure natural gas to operate. In these ``gas-
driven'' pneumatic controllers, natural gas may be released with every
valve movement or continuously from the valve control pilot. The rate
at which this release occurs is referred to as the device bleed rate.
Bleed rates are dependent on the design of the device. Similar designs
will have similar steady-state rates when operated under similar
conditions. Gas-driven pneumatic controllers are typically
characterized as ``high-bleed'' or ``low-bleed,'' where a high-bleed
device releases more than 6 standard cubic feet per hour (scfh) of gas,
with 18 scfh bleed rate being what we used in our analyses below. There
are three basic designs: (1) Continuous bleed devices (high or low-
bleed) are used to modulate flow, liquid level or pressure and gas is
vented at a steady-state rate; (2) actuating/intermittent devices (high
or low-bleed) perform quick control movements and only release gas when
they open or close a valve or as they throttle the gas flow; and (3)
self-contained devices release gas to a downstream pipeline instead of
to the atmosphere. We are not aware of any add-on controls that are or
can be used to reduce VOC emissions from gas-driven pneumatic devices.
For an average high-bleed pneumatic controller located in
production (where the content of VOC in the raw product stream is
relatively high), the difference in VOC emissions between a high-bleed
controller and a low-bleed controller is around 1.8 tpy. For the
transmission and storage segment (where the content of VOC in the
pipeline quality gas is relatively low), the difference in VOC
emissions between a high-bleed controller and a low-bleed controller is
around 0.89 tpy. We have developed projections that estimate that
approximately 13,600 new gas-driven units in the production segment and
67 new gas-driven units in the transmission and storage segment will be
installed each year, including replacement of old units. Not all
pneumatic controllers are gas driven. These ``non-gas driven''
pneumatic controllers use sources of power other than pressurized
natural gas, such as compressed ``instrument air.'' Because these
devices are not gas driven, they do not release natural gas or VOC
emissions, but they do have energy impacts because electrical power is
required to drive the instrument air compressor system. Electrical
service of at least 13.3 kilowatts (kW) is required to power a 10
horsepower (hp) instrument air compressor, which is a relatively small
capacity compressor. At sites without available electrical service
sufficient to power an instrument air compressor, only gas driven
pneumatic devices can be used. During our review, we determined that
gas processing plants are the only facilities in the oil and natural
gas sector highly likely to have electrical service sufficient to power
an instrument air system, and that approximately half of existing gas
processing plants are using non-gas driven devices.
For devices at gas processing plants, we evaluated the use of non-
gas driven controllers and low-bleed controllers as options for
reducing VOC emissions, with high-bleed controllers being the baseline.
As mentioned above, non-gas driven devices themselves have zero
emissions, but they do have energy impacts because electrical power is
required to drive the instrument air compressor system. In our cost
analysis, we determined that the annualized cost of installing and
operating a fully redundant 10 hp (13.3 kW) instrument air system
(systems generally are designed with redundancy to allow for system
maintenance and failure without loss of air pressure), including
duplicate compressors, air tanks and dryers, would be $11,090. A system
of this size is capable of serving 15 control loops and reducing VOC
emissions by 4.2 tpy, for a cost effectiveness of $2,659 per ton of VOC
reduced. If the savings of the salable natural gas that would have been
emitted is considered, the value of the gas not emitted would help
offset the cost for this control, bringing the cost per ton of VOC down
to $1,824.
We also evaluated the use of low-bleed controllers in place of
high-bleed controllers at processing plants. We evaluated the impact of
bleeding 6 standard cubic feet of natural gas per hour, which is the
maximum bleed rate from low-bleed controllers, according to
manufacturers of these devices. We chose natural gas as a surrogate for
VOC, because manufacturers' technical specifications for pneumatic
controllers are stated in terms of natural gas bleed rate rather than
VOC. The capital cost difference between a new high-bleed controller
and a new low-bleed controller is estimated to be $165. Without taking
into account the savings due to the natural gas losses avoided, the
annual costs are estimated to be around $23 per year, which is a cost
of $13 per ton of VOC reduced for the production segment. If the
savings of the salable natural gas that would have been emitted is
considered, there is a net savings of $1,519 per ton of VOC reduced.
Although the non-gas-driven controller system is more expensive
than the low-bleed controller system, it is still reasonably cost-
effective. Furthermore, the non-gas-driven controller system achieves a
100-percent VOC reduction in contrast to a 66-percent reduction
achieved by a low-bleed controller. Moreover, we believe the collateral
emissions from electrical power generation needed to run the compressor
are very low. Finally, non-gas-driven pneumatic controllers avoid
potentially explosive concentrations of natural gas which can occur as
a result of normal bleeding from groups of gas-driven pneumatic
controllers located in close proximity, as they often are at gas
processing plants. Based on our review described above, we believe that
a non-gas-driven controller is BSER for reducing VOC emissions from
pneumatic devices at gas processing plants. Accordingly, the proposed
standard for pneumatic devices at gas processing plants is a zero VOC
emission limit.
For the production (other than processing plants) and transmission
and storage segments, where electrical service sufficient to power an
instrument air system is likely
[[Page 52761]]
unavailable and, therefore, only gas-driven devices can be used, we
evaluated the use of low-bleed controllers in place of high-bleed
controllers. Just as in our analysis of low-bleed controllers as an
option for gas processing plants, we evaluated the impact of bleeding 6
standard cubic feet per minute (scfm) of natural gas per hour
contrasted with 18 scfm from a high-bleed unit. Again, the capital cost
difference between a new high-bleed controller and a new low-bleed
controller is estimated to be $165. Without taking into account the
savings due to the natural gas losses avoided, the annual costs are
estimated to be around $23 per year, which is a cost of $13 per ton of
VOC reduced for the production segment. If the savings of the salable
natural gas that would have been emitted is considered, there is a net
savings for this control. In the transmission and storage segment,
where the VOC content of the vented gas is much lower than in the
production segment, the cost effectiveness of a low-bleed pneumatic
device is estimated to be around $262 per ton of VOC reduced. However,
there are no potential offsetting savings to be realized in the
transmission and storage segment, since the operators of transmission
and storage stations typically do not own the gas they are handling.
Based on our evaluation of the emissions and costs, we believe that
low-bleed controllers represent BSER for pneumatic controllers in the
production (other than processing plants) and transmission and storage
segments. Therefore, for pneumatic devices at these locations, we
propose a natural gas bleed rate limit of 6.0 scfh to reflect the VOC
limit with the use of a low-bleed controller.
There may be situations where high-bleed controllers and the
attendant gas bleed rate greater than 6 cubic feet per hour, are
necessary due to functional requirements, such as positive actuation or
rapid actuation. An example would be controllers used on large
emergency shutdown valves on pipelines entering or exiting compression
stations. For such situations, we have provided in the proposed rule an
exemption where pneumatic controllers meeting the emission standards
discussed above would pose a functional limitation due to their
actuation response time or other operating characteristics. We are
requesting comments on whether there are other situations that should
be considered for this exemption. If you provide such comment, please
specify the criteria for such situations that would help assure that
only appropriate exemptions are claimed.
The proposed standards would apply to installation of a new
pneumatic device (including replacing an existing device with a new
device). We consider that a pneumatic device, an apparatus, is an
affected facility and each installation is construction subject to the
proposed NSPS. See definitions of ``affected facility'' and
``construction'' at 40 CFR 60.2.
c. NSPS for Compressors
There are many locations throughout the oil and natural gas sector
where compression of natural gas is required to move it along the
pipeline. This is accomplished by compressors powered by combustion
turbines, reciprocating internal combustion engines or electric motors.
Turbine-powered compressors use a small portion of the natural gas that
they compress to fuel the turbine. The turbine operates a centrifugal
compressor, which compresses the natural gas for transit through the
pipeline. Sometimes an electric motor is used to turn a centrifugal
compressor. This type of compressor does not require the use of any of
the natural gas from the pipeline, but it does require a substantial
source of electricity. Reciprocating spark ignition engines are also
used to power many compressors, referred to as reciprocating
compressors, since they compress gas using pistons that are driven by
the engine. Like combustion turbines, these engines are fueled by
natural gas from the pipeline. Both centrifugal and reciprocating
compressors are sources of VOC emissions and were evaluated for
coverage under the NSPS.
Centrifugal Compressors. Centrifugal compressors require seals
around the rotating shaft to minimize gas leakage and fugitive VOC
emissions from where the shaft exits the compressor casing. There are
two types of seal systems: Wet seal systems and mechanical dry seal
systems.
Wet seal systems use oil, which is circulated under high pressure
between three or more rings around the compressor shaft, forming a
barrier to minimize compressed gas leakage. Very little gas escapes
through the oil barrier, but considerable gas is absorbed by the oil.
The amount of gas absorbed and entrained by the oil barrier is affected
by the operating pressure of the gas being handled; higher operating
pressures result in higher absorption of gas into the oil. Seal oil is
purged of the absorbed and entrained gas (using heaters, flash tanks
and degassing techniques) and recirculated to the seal area for reuse.
Gas that is purged from the seal oil is commonly vented to the
atmosphere. Degassing of the seal oil emits an average of 47.7 scfm of
gas, depending on the operating pressure of the compressor. An
uncontrolled wet seal system can emit, on average, approximately 20.5
tpy of VOC during the venting process (production segment) or about 3.5
tpy (transmission and storage segment). We identified two potential
control techniques for reducing emissions from degassing of wet seal
systems: (1) Routing the gas back to a low pressure fuel stream to be
combusted as fuel gas and (2) routing the gas to a flare. We know only
of anecdotal, undocumented information on routing of the gas back to a
fuel stream and, therefore, were unable to assess costs and cost
effectiveness of the first option. Although we do not have specific
examples of routing emissions from wet seal degassing to a flare, we
were able to estimate the cost, emission reductions and cost
effectiveness of the second option using uncontrolled wet seals as a
baseline.
Based on the average uncontrolled emissions of wet seal systems
discussed above and a flare efficiency of 95 percent, we determined
that VOC emission reductions from a wet seal system would be an average
of 19.5 tpy (production segment) or 3.3 tpy (transmission and storage
segment). Using an annualized cost of flare installation and operation
of $103,373, we estimated the incremental cost effectiveness of this
option (from uncontrolled wet seals to controlled wet seals using a
flare) to be approximately $5,300/ton and $31,000/ton for the
production segment and transmission and storage segment, respectively.
With this option, there would be secondary air impacts from combustion.
However we did not identify any nonair quality or energy impacts
associated with this control technique.
Dry seal systems do not use any circulating seal oil. Dry seals
operate mechanically under the opposing force created by hydrodynamic
grooves and springs. Fugitive emissions occur from dry seals around the
compressor shaft. Based on manufacturer studies and engineering design
estimates, fugitive emissions from dry seal systems are approximately 6
scfm of gas, depending on the operating pressure of the compressor. A
dry seal system can have fugitive emissions of, on average,
approximately 2.6 tpy of VOC (production segment) or about 0.4 tpy
(transmission and storage segment). We did not identify any control
device suitable to capture and control the fugitive emissions from dry
seals around the compressor shaft.
[[Page 52762]]
Using uncontrolled wet seals as a baseline, we evaluated the
reductions and incremental cost effectiveness of dry seal systems.
Based on the average fugitive emissions, we determined that VOC
emission reductions achieved by dry seal systems compared to
uncontrolled wet seal systems would be 18 tpy (production segment) and
3.1 tpy (transmission and storage segment). Combined with an annualized
cost of dry seal systems of $10,678, the incremental cost effectiveness
compared to uncontrolled wet seal systems would be $595/ton and $3,495/
ton for the production segment and transmission and storage segment,
respectively. We identified neither nonair quality nor any energy
impacts associated with this option.
In performing our analysis, we estimated the incremental cost of a
dry seal compressor over that of an equivalent wet seal compressor to
be $75,000. This value was obtained from a vendor who represents a
large share of the market for centrifugal compressors. However, this
number likely represents a conservatively high value because wet seal
units have a significant amount of ancillary equipment, namely the seal
oil system and, thus, additional capital expenses. Dry seal systems
have some ancillary equipment (the seal gas filtration system), but the
costs are less than the wet seal oil system. We were not able to
directly confirm this assumption with the vendor, however, a search of
product literature showed that seal oil systems and seal gas filtration
systems are typically listed separate from the basic compressor
package. Using available data on the cost of this equipment, it is very
likely that the cost of purchasing a dry seal compressor may actually
be lower that a wet seal compressor. We seek comment on available cost
data of a dry seal versus wet seal compressor, including all ancillary
equipment costs.
In light of the above analyses, we propose to determine that dry
seal systems are BSER for reducing VOC emissions from centrifugal
compressors. We evaluated the possibility of setting a performance
standard that reflects the emission limitation achievable through the
use of a dry seal system. However, as mentioned above, VOC from
centrifugal compressors with dry seals are fugitive emissions from
around the compressor shafts. There is no device to capture and control
these fugitive emissions, nor can reliable measurement of these
emissions be conducted due to difficulty in accessing the leakage area
and danger of contacting the shaft rotating at approximately 30,000
revolutions per minute. This not only poses a likely hazard that would
destroy test equipment on contact, it poses a safety hazard to
personnel, as well. Therefore, pursuant to section 111(h)(2) of the
CAA, we are proposing an equipment standard that would require the use
of dry seals to limit the VOC emissions from new centrifugal
compressors. We consider that a centrifugal compressor, an apparatus,
is an affected facility and each installation is construction subject
to the proposed NSPS. See definitions of ``affected facility'' and
``construction'' at 40 CFR 60.2. Accordingly, the proposed standard
would apply to installation of new centrifugal compressors at new
locations, as well as replacement of old compressors.
Although we are proposing to determine dry seal systems to be BSER
for centrifugal compressors, we are soliciting comments on the emission
reduction potential, cost and any limitations for the option of routing
the gas back to a low pressure fuel stream to be combusted as fuel gas.
In addition, we solicit comments on whether there are situations or
applications where wet seal is the only option, because a dry seal
system is infeasible or otherwise inappropriate.
Reciprocating Compressors. Reciprocating compressors in the natural
gas industry leak natural gas fugitive VOC during normal operation. The
highest volumes of gas loss and fugitive VOC emissions are associated
with piston rod packing systems. Packing systems are used to maintain a
tight seal around the piston rod, preventing the high pressure gas in
the compressor cylinder from leaking, while allowing the rod to move
freely. This leakage rate is dependent on a variety of factors,
including physical size of the compressor piston rod, operating speed
and operating pressure. Under the best conditions, new packing systems
properly installed on a smooth, well-aligned shaft can be expected to
leak a minimum of 11.5 scfh. Higher leak rates are a consequence of
fit, alignment of the packing parts and wear.
We evaluated the possibility of reducing VOC emissions from
reciprocal compressors through a control device. However, VOC from
reciprocating compressors are fugitive emissions from around the
compressor shafts. Although it is possible to construct an enclosure
around the rod packing area and vent the emissions outside for safety
purposes, connection to a closed vent system and control device would
create back pressure on the leaking gas. This back pressure would cause
the leaked gas instead to be forced inside the crankcase of the engine,
which would dilute lubricating oil, causing premature failure of engine
bearings, pose an explosion hazard and eventually be vented from the
crankcase breather, defeating the purpose of a control device.
As mentioned above, as packing wears and deteriorates, leak rates
can increase. We, therefore, evaluate replacement of compressor rod
packing systems as an option for reducing VOC emissions. Conventional
bronze-metallic packing rings wear out and need to be replaced every 3
to 5 years, depending on the compressor's rate of usage (i.e., the
percentage of time that a compressor is in pressurized mode).
Based on industry experience in the Natural Gas STAR program and
other sources, we evaluated the rod packing replacement costs for
reciprocating compressors at different segments of this industry. Usage
rates vary by segment. Usage rates for compressors at wellheads,
gathering/boosting stations, processing plants, transmission stations
and storage facilities are 100, 79, 90, 79 and 68 percent,
respectively. Reciprocating compressors at wellheads are small and
operate at lower pressures, which limit VOC emissions from these
sources. Due to the low VOC emissions from these compressors, about
0.044 tpy, combined with an annual cost of approximately $3,700, the
cost per ton of VOC reduction is rather high. We estimated that the
cost effectiveness of controlling wellhead compressors is over $84,000
per ton of VOC reduced, which we believe to be too high and, therefore,
not reasonable. Because the cost effectiveness of replacing packing
wellhead compressor rod systems is not reasonable, and absent other
emission reduction measures, we did not find a BSER for reducing VOC
emissions from reciprocal compressors at wellheads.
For reciprocating compressors located at other oil and gas
operations, we estimated that the cost effectiveness of controlling
compressor VOC emissions by rod packing replacement would be $870 per
ton of VOC for reciprocating compressors at gathering and boosting
stations, $270 per ton of VOC for reciprocating compressors at
processing stations, $2,800 per ton of VOC for reciprocating
compressors at transmission stations and $3,700 per ton of VOC for
reciprocating compressors at underground storage facilities. We
consider these costs to be reasonable. We did not identify any nonair
quality health or environmental impacts or energy impacts associated
with rod packing replacement. In light of the above, we propose to
determine that such control is the BSER for reducing
[[Page 52763]]
VOC emission from compressors at these other oil and gas operations.
Because VOC emitted from reciprocal compressors are fugitive
emissions, there is no device to capture and control the emissions.
Therefore, pursuant to section 111(h) of the CAA, we are proposing an
operational standard. Based on industry experience reported to the
Natural Gas STAR program, we determined that packing rods should be
replaced every 3 years of operation. However, to account for segments
of the industry in which reciprocating compressors operate in
pressurized mode a fraction of the calendar year (ranging from
approximately 68 percent up to approximately 90 percent), the proposed
rule expresses the replacement requirement in terms of hours of
operation rather than on a calendar year basis. One year of continuous
operation would be 8,760 hours. Three years of continuous operation
would be 26,280 hours, or rounded to the nearest thousand, 26,000
hours. Accordingly, the proposed rule would require the replacement of
the rod packing every 26,000 hours of operation. The owner or operator
would be required to monitor the hours of operation beginning with the
installation of the reciprocating compressor affected facility.
Cumulative hours of operation would be reported each year in the
facility's annual report. Once the hours of operation reached 26,000
hours, the owner or operator would be required to change the rod
packing immediately, although unexpected shutdowns could be avoided by
tracking hours of operation and planning for packing replacement at
scheduled maintenance shutdowns before the hours of operation reached
26,000.
Some industry partners of the Natural Gas STAR program currently
conduct periodic testing to determine the leakage rates that would
identify economically beneficial replacement of rod packing based on
natural gas savings. Therefore, we are soliciting comments on
incorporating a method similar to that in the Natural Gas STAR's
Lessons Learned document entitled, Reducing Methane Emissions from
Compressor Rod Packing Systems (http://www.epa.gov/gasstar/documents/ll_rodpack.pdf), to be incorporated in the NSPS. We are soliciting
comments on how to determine a suitable leak threshold above which rod
packing replacement would be cost effective for VOC emission reduction.
We are also soliciting comment on the appropriate replacement frequency
and other considerations that would be associated with regular
replacement periods.
d. NSPS for Storage Vessels
Crude oil, condensate and produced water are typically stored in
fixed-roof storage vessels. Some vessels used for storing produced
water may be open-top tanks. These vessels, which are operated at or
near atmospheric pressure conditions, are typically located as part of
a tank battery. A tank battery refers to the collection of process
equipment used to separate, treat and store crude oil, condensate,
natural gas and produced water. The extracted products from productions
wells enter the tank battery through the production header, which may
collect product from many wells.
Emissions from storage vessels are a result of working, breathing
and flash losses. Working losses occur due to the emptying and filling
of storage tanks. Breathing losses are the release of gas associated
with daily temperature fluctuations and other equilibrium effects.
Flash losses occur when a liquid with dissolved gases is transferred
from a vessel with higher pressure to a vessel with lower pressure,
thus, allowing dissolved gases and a portion of the liquid to vaporize
or flash. In the oil and natural gas production segment, flashing
losses occur when live crude oils or condensates flow into a storage
tank from a processing vessel operated at a higher pressure. Typically,
the larger the pressure drop, the more flash emissions will occur in
the storage stage. Temperature of the liquid also influences the amount
of flash emissions. The amount of liquid entering the tank during a
given time, commonly known as throughput, also affects the emission
rate, with higher throughput tanks having higher annual emissions,
given that other parameters are the same.
In analyzing controls for storage vessels, we reviewed control
techniques identified in the Natural Gas STAR program and state
regulations. We identified two ways of controlling storage vessel
emissions, both of which can reduce VOC emissions by 95 percent. One
option would be to install a vapor recovery unit (VRU) and recover all
the vapors from the tanks. The other option would be to route the
emissions from the tanks to a flare control device. These devices could
be ``candlestick'' flares that are found at gas processing plants or
other larger facilities or enclosed combustors which are commonly found
at smaller field facilities. We estimated the total annual cost for a
VRU to be approximately $18,900/yr and for a flare to be approximately
$8,900/yr. Cost effectiveness of these control options depend on the
amount of vapor produced by the storage vessels being controlled. A VRU
has a potential advantage over flaring, in that it recovers hydrocarbon
vapors that potentially can be used as supplemental burner fuel, or the
vapors can be condensed and collected as condensate that can be sold.
If natural gas is recovered, it can be sold, as well, as long as a
gathering line is available to convey the recovered salable gas product
to market or to further processing. A VRU also does not have secondary
air impacts that flaring does, as described below. However, a VRU
cannot be used in all instances. Some conditions that affect the
feasibility of VRU are: Availability of electrical service sufficient
to power the VRU; fluctuations in vapor loading caused by surges in
throughput and flash emissions from the tank; potential for drawing air
into condensate tanks causing an explosion hazard; and lack of
appropriate destination or use for the vapor recovered.
Like a VRU, a flare control device can also achieve a control
efficiency of 95 percent. There are no technical limitations on the use
of flares to control vapors from condensate and crude oil tanks.
However, flaring has a secondary impact from emissions of
NOX and other pollutants. In light of the technical
limitations with the use of a VRU, we are unable to conclude that a VRU
is better than flaring. We, therefore, propose to determine that both a
VRU and flare are BSER for reducing VOC emission from storage vessels.
We propose an NSPS of 95-percent reduction for storage vessels to
reflect the level of emission reduction achievable by VRU and flares.
VOC emissions from storage vessels vary significantly, depending on
the rate of liquid entering and passing through the vessel (i.e., its
throughput), the pressure of the liquid as it enters the atmospheric
pressure storage vessel, the liquid's volatility and temperature of the
liquid. Some storage vessels have negligible emissions, such as those
with very little throughput and/or handling heavy liquids entering at
atmospheric pressure. We do not believe that it is cost effective to
control these vessels. We believe it is important to control tanks with
significant VOC emissions under the proposed NSPS.
In our analysis, we evaluated storage tanks with varying condensate
or crude oil throughput. We used emission factors developed for the
Texas Environmental Research Consortium in a study that evaluated VOC
emissions from crude oil and condensate storage tanks by performing
direct
[[Page 52764]]
measurements. The study found that the average VOC emission factor for
crude oil storage tanks was 1.6 pounds (lb) VOC per barrel of crude oil
throughput. The average VOC emission factor for condensate tanks was
determined to be 33.3 lb VOC per barrel of condensate throughput.
Applying these emission factors and evaluating condensate throughput
rates of 0.5, 1, 2 and 5 barrels per day (bpd), we determined that VOC
emissions at these condensate throughput rates would be approximately
3, 6, 12 and 30 tpy, respectively. Similarly, we evaluated crude oil
throughput rates of 1, 5, 20 and 50 bpd. Based on the Texas study,
these crude oil throughput rates would result in VOC emissions of 0.3,
1.5, 5.8 and 14.6 tpy, respectively. We believe that it is important to
control tanks with significant VOC emissions. Furthermore, we believe
it would be easier and less costly for owners and operators to
determine applicability by using a throughput threshold instead of an
emissions threshold. As a result of the above analyses, we believe that
storage vessels with at least 1 bpd of condensate or 20 bpd of crude
oil should be controlled. These throughput rates are equivalent to VOC
emissions of approximately 6 tpy. Based on an estimated annual cost of
$18,900 for the control device, controlling storage vessels with these
condensate or crude oil throughputs would result in a cost
effectiveness of $3,150 per ton of VOC reduced.
Based on our evaluation, we propose to determine that both a VRU
and flare are BSER for reducing VOC emission from storage vessels with
throughput of at least 1 barrel of condensate per day or 20 barrels of
crude oil per day. We propose an NSPS of 95-percent reduction for these
storage vessels to reflect the level of emission reduction achievable
by VRU and flare control devices.
For storage vessels below the throughput levels described above
(``small throughput tanks''), for which we do not consider flares or
VRU to be cost effective controls, we evaluated other measures to
reduce VOC emissions. Standard practices for such tanks include
requiring a cover that is well designed, maintained in good condition
and kept closed. Crude oil and condensate storage tanks in the oil and
natural gas sector are designed to operate at or just slightly above or
below atmospheric pressure. Accordingly, they are provided with vents
to prevent tank destruction under rapid pressure increases due to flash
emissions conditions. Studies by the Natural Gas STAR program and by
others have shown that working losses (i.e., those emissions absent
flash emission conditions) are very low, approaching zero. During times
of flash emissions, tanks are designed such that the flash emissions
are released through a vent on the fixed roof of the tank when pressure
reaches just a few ounces to prevent pressure buildup and resulting
tank damage. At those times, vapor readily escapes through the vent to
protect the tank. Tests have shown that open hatches or leaking hatch
gaskets have little effect on emissions from uncontrolled tanks due to
the functioning roof vent. However, in the case of controlled tanks,
the control requirements include provisions for maintaining integrity
of the closed vent system that conveys emissions to the control device,
including hatches and other tank openings. As a result, hatches are
required to be kept closed and gaskets kept in good repair to meet
control requirements of controlled storage vessels. Because the
measures we evaluated, including maintenance of hatch integrity, do not
provide appreciable emission reductions for storage vessels with
throughputs under 1 barrel of condensate per day and 21 barrels of
crude oil per day, we believe that the control options we evaluated do
not reflect BSER for the small throughput tanks and we are not
proposing standards for these tanks.
As discussed in section VII of this preamble, we are proposing to
amend the NESHAP for oil and natural gas production facilities at 40
CFR part 63, subpart HH to require that all storage vessels at
production facilities reduce HAP emissions by 95 percent. Because the
controls used to achieve the 95-percent HAP reduction are the same as
the proposed BSER for VOC reduction for storage vessels (i.e., VRU and
flare), sources that are achieving the 95- percent HAP reduction would
also be meeting the proposed NSPS of 95-percent VOC reduction. In light
of the above, and to avoid duplicate monitoring, recordkeeping and
reporting, we propose that storage vessels subject to the requirements
of subpart HH are exempt from the proposed NSPS for storage vessel in
40 CFR part 60, subpart OOOO.
e. NSPS for VOC Equipment Leaks
Equipment leaks are fugitive emissions emanating from valves, pump
seals, flanges, compressor seals, pressure relief valves, open-ended
lines and other process and operation components. There are several
potential reasons for equipment leak emissions. Components such as
pumps, valves, pressure relief valves, flanges, agitators and
compressors are potential sources that can leak due to seal failure.
Other sources, such as open-ended lines and sampling connections may
leak for reasons other than faulty seals. In addition, corrosion of
welded connections, flanges, and valves may also be a cause of
equipment leak emissions. Because of the large number of valves, pumps
and other components within an oil and gas production, processing and
transmission facility, equipment leak volatile emissions from these
components can be significant. Natural gas processing plants,
especially those using refrigerated absorption and transmission
stations tend to have a large number of components. Equipment leaks
from processing plants are addressed in our review of 40 CFR part 60,
subpart KKK, which is discussed above in section VI.B.1.
In addition to gas processing plants, these types of equipment also
exist at oil and gas production sites and gas transmission and storage
facilities. While the number of components at individual transmission
and storage facilities is relatively smaller than at processing plants,
collectively, there are many components that can result in significant
emissions.
Therefore, we evaluated applying NSPS for equipment leaks to
facilities in the production segment of the industry, which includes
everything from the wellhead to the point that the gas enters the
processing plant, transmission pipeline or distribution pipeline.
Production facilities can vary significantly in the operations
performed and the processes, all of which impact the number of
components and potential emissions from leaking equipment and, thus,
impact the annual costs related to implementing a LDAR program. We used
data collected by the Gas Research Institute to develop model
production facilities. Baseline emissions, along with emission
reductions and costs of regulatory alternatives, were estimated using
these model production facilities. We considered production facilities
where separation, storage, compression and other processes occur. These
facilities may not have a wellhead on-site, but would be associated
with a wellhead. We also evaluated gathering and boosting facilities,
where gas and/or oil are collected from a number of wells, then
processed and transported downstream to processing plants or
transmission stations. We evaluated the impacts at these production
facilities with varying number of operations and equipment. We also
developed a model plant for the transmission and storage segment using
data from the Gas
[[Page 52765]]
Research Institute. Details of these evaluations may be found in the
TSD in the docket.
For an average production site at or associated with a wellhead, we
estimated annual VOC emissions from equipment leaks of around 2.6 tpy.
For an average gathering/boosting facility, we estimated the annual VOC
emissions from equipment leaks to be around 9.8 tpy. The average
transmission and storage facility emits 2.7 tpy of VOC.
For facilities in each non-gas processing plant segment, we
evaluated the same four options as we did for gas processing plants in
section VI.B.1 above. These four options are as follows: (1) 40 CFR
part 60, subpart VVa-level LDAR (which is based on conducting Method 21
monthly, defining ``leak'' at 500 ppm threshold, and adding connectors
to the VV list of components to be monitored); (2) monthly optical gas
imaging with annual Method 21 check (the alternative work practice for
monitoring equipment for leaks at 40 CFR 60.18(g)); (3) monthly optical
gas imaging alone; and (4) annual optical gas imaging alone.
For option 1, we evaluated subpart VVa-LDAR as a whole. We also
analyzed separately the individual types of components (valves,
connectors, pressure relief devices and open-ended lines). Detailed
discussions of these component by component analyses are included in
the TSD in the docket.
Based on our evaluation, subpart VVa-level LDAR (Option 1) results
in more VOC reduction than the subpart VV-level LDAR currently required
for gas processing plants, because more leaks are found based on the
lower definition of ``leak'' under subpart VVa (10,000 ppm for subpart
VV and 500 ppm for subpart VVa). In addition, our evaluation shows that
the cost per ton of VOC reduced for subpart VVa level controls is less
than the cost per ton of VOC reduced for the less stringent subpart VV
level of control. Although the cost of repairing more leaks is higher,
the increased VOC control afforded by subpart VVa level controls more
than offsets the increased costs.
For the subpart VVa level of control at the average production site
associated with a wellhead, average facility-wide cost-effectiveness
would be $16,084 per ton of VOC. Component-specific cost-effectiveness
ranged from $15,063 per ton of VOC (for valves) to $211,992 per ton of
VOC (for pressure relief devices), with connectors and open-ended lines
being $74,283 and $180,537 per ton of VOC, respectively. We also looked
at component costs for a modified subpart VVa level of control with
less frequent monitoring for valves and connectors at production sites
associated with a wellhead.\12\ The cost-effectiveness for valves was
calculated to be $17,828 per ton of VOC by reducing the monitoring
frequency from monthly to annually. The cost-effectiveness for
connectors was calculated to be $87,277 per ton of VOC by reducing the
monitoring frequency from every 4 years to every 8 years after the
initial compliance period.
We performed a similar facility-wide and component-specific
analysis of option 1 LDAR for gathering and boosting stations. For the
subpart VVa level of control at the average gathering and boosting
station, facility-wide cost-effectiveness was estimated to be $9,344
per ton of VOC. Component-specific cost-effectiveness ranged from
$6,079 per ton of VOC (for valves) to $77,310 per ton of VOC (for open-
ended lines), with connectors and pressure relief devices being $23,603
and $72,523 per ton, respectively. For the modified subpart VVa level
of control at gathering and boosting stations, cost-effectiveness
ranged from $5,221 per ton of VOC (for valves) to $77,310 per ton of
VOC (for open-ended lines), with connectors and pressure relief devices
being $27,274 and $72,523 per ton, respectively. The modified subpart
VVa level controls were more cost-effective than the subpart VVa level
controls for valves, but not for connectors. This is due to the low
cost of monitoring connectors and the low VOC emissions from leaking
connectors.
We also performed a similar analysis of option 1 subpart VVa-level
LDAR for gas transmission and storage facilities. For the subpart VVa
level of control at the average transmission and storage facility,
facility-wide cost-effectiveness was $20,215. Component-specific cost-
effectiveness ranged from $24,762 per ton of VOC (for open-ended lines)
to $243,525 per ton of VOC (for pressure relief devices), with
connectors and valves being $36,527 and $43,111 per ton of VOC,
respectively. For the modified subpart VVa level of control at
transmission and storage facilities, cost-effectiveness ranged from
$24,762 per ton of VOC (for open-ended lines) to $243,525 per ton of
VOC (for pressure relief devices), with connectors and valves being
$42,140 and $40,593 per ton of VOC, respectively. Again, the modified
subpart VVa level controls were more cost-effective for valves and less
cost effective for connectors than the subpart VVa level controls. This
is due to the low cost of monitoring connectors and the low VOC
emissions from leaking connectors.
For each of the non-gas processing segments, we also evaluated
monthly optical gas imaging with annual Method 21 check (Option 2). As
discussed in secton VI.B.1, we had previously determined that the VOC
reductions achieved under this option would be the same as for option 1
subpart VVa-level LDAR. In our evaluation of Option 2, we estimated
that a single optical imaging instrument could be used for 160 well
sites and 13 gathering and boosting stations, which means that the cost
of the purchase or rental of the camera would be spread across 173
facilities.
For production sites, gathering and boosting stations, and
transmission and storage facilities, we estimated that option 2 monthly
optical gas imaging with annual Method 21 check would have cost-
effectiveness of $16,123, $10,095, and $19,715 per ton of VOC,
respectively.\13\
---------------------------------------------------------------------------
\13\ Because optical gas imaging is used to view several pieces
of equipment at a facility at once to survey for leaks, options
involving imaging are not amenable to a component by component
analysis.
---------------------------------------------------------------------------
The annual costs for option 1 and option 2 leak detection and
repair programs for production sites associated with a wellhead,
gathering and boosting stations and transmission and storage facilities
were higher than those estimated for natural gas processing plants
because natural gas processing plant annual costs are based on the
incremental cost of implementing subpart VVa-level standards, whereas
the other facilities are not currently regulated under an LDAR program.
The currently unregulated sites would be required to set up a new LDAR
program; perform initial monitoring, tagging, logging and repairing of
components; as well as planning and training personnel to implement the
new LDAR program.
In addition to options 1 and 2, we evaluated a third option that
consisted of monthly optical gas imaging without an annual Method 21
check. Because we were unable to estimate the VOC emissions achieved by
an optical imaging program alone, we were unable to estimate the cost-
effectiveness of this option. However, we estimated the annual cost of
the monthly optical gas imaging LDAR program at production sites,
gathering and boosting stations, and transmission and storage
facilities to be $37,049, $86,135, and $45,080, respectively, based on
camera purchase, or $32,693, $81,780, and $40,629, respectively, based
on camera rental.
Finally, we evaluated a fourth option similar to the third option
except that the optical gas imaging would be performed annually rather
than monthly. For this option, we estimated the annual cost for
production sites, gathering and boosting stations, and transmission and
storage facilities to be
[[Page 52766]]
$30,740, $64,416, and $24,031, respectively, based on camera purchase,
or $26,341, $60,017, and $19,493, respectively, based on camera rental.
We request comment on the applicability of a leak detection and
repair program based solely on the use of optical imaging or other
technologies. Of most use to us would be information on the
effectiveness of advanced measurement technologies to detect and repair
small leaks on the same order or smaller as specified in the VVa
equipment leak requirements and the effects of increased frequency of
and associated leak detection, recording, and repair practices.
Based on the evaluation described above, we believe that neither
option 1 nor option 2 is cost effective for reducing fugitive VOC
emissions from equipment leaks at sites, gathering and boosting
stations, and transmission and storage facilities. For options 3 and 4,
we were unable to estimate their cost effectiveness and, therefore,
could not identify either of these two options as BSER for addressing
equipment leak of VOC at production facilities associated with
wellheads, at gathering and boosting stations or at gas transmission
and storage facilities. We are, therefore, not proposing NSPS for
addressing VOC emissions from equipment leaks at these facilities.
5. What are the SSM provisions?
The EPA is proposing standards in this rule that apply at all
times, including during periods of startup or shutdown, and periods of
malfunction. In proposing the standards in this rule, the EPA has taken
into account startup and shutdown periods.
The General Provisions in 40 CFR part 60 require facilities to keep
records of the occurrence and duration of any startup, shutdown or
malfunction (40 CFR 60.7(b)) and either report to the EPA any period of
excess emissions that occurs during periods of SSM (40 CFR 60.7(c)(2))
or report that no excess emissions occurred (40 CFR 60.7(c)(4)). Thus,
any comments that contend that sources cannot meet the proposed
standard during startup and shutdown periods should provide data and
other specifics supporting their claim.
Periods of startup, normal operations and shutdown are all
predictable and routine aspects of a source's operations. However, by
contrast, malfunction is defined as a ``sudden, infrequent, and not
reasonably preventable failure of air pollution control and monitoring
equipment, process equipment or a process to operate in a normal or
usual manner * * *'' (40 CFR 60.2.) The EPA has determined that
malfunctions should not be viewed as a distinct operating mode and,
therefore, any emissions that occur at such times do not need to be
factored into development of CAA section 111 standards. Further,
nothing in CAA section 111 or in case law requires that the EPA
anticipate and account for the innumerable types of potential
malfunction events in setting emission standards. See, Weyerhaeuser v
Costle, 590 F.2d 1011, 1058 (D.C. Cir. 1978) (``In the nature of
things, no general limit, individual permit, or even any upset
provision can anticipate all upset situations. After a certain point,
the transgression of regulatory limits caused by `uncontrollable acts
of third parties,' such as strikes, sabotage, operator intoxication or
insanity, and a variety of other eventualities, must be a matter for
the administrative exercise of case-by-case enforcement discretion, not
for specification in advance by regulation.''), and, therefore, any
emissions that occur at such times do not need to be factored into
development of CAA section 111 standards.
Further, it is reasonable to interpret CAA section 111 as not
requiring the EPA to account for malfunctions in setting emissions
standards. For example, we note that CAA section 111 provides that the
EPA set standards of performance which reflect the degree of emission
limitation achievable through ``the application of the best system of
emission reduction'' that the EPA determines is adequately
demonstrated. Applying the concept of ``the application of the best
system of emission reduction'' to periods during which a source is
malfunctioning presents difficulties. The ``application of the best
system of emission reduction'' is more appropriately understood to
include operating units in such a way as to avoid malfunctions.
Moreover, even if malfunctions were considered a distinct operating
mode, we believe it would be impracticable to take malfunctions into
account in setting CAA section 111 standards for affected facilities
under 40 CFR part 60, subpart OOOO. As noted above, by definition,
malfunctions are sudden and unexpected events and it would be difficult
to set a standard that takes into account the myriad different types of
malfunctions that can occur across all sources in the category.
Moreover, malfunctions can vary in frequency, degree and duration,
further complicating standard setting.
In the event that a source fails to comply with the applicable CAA
section 111 standards as a result of a malfunction event, the EPA would
determine an appropriate response based on, among other things, the
good faith efforts of the source to minimize emissions during
malfunction periods, including preventative and corrective actions, as
well as root cause analyses to ascertain and rectify excess emissions.
The EPA would also consider whether the source's failure to comply with
the CAA section 111 standard was, in fact, ``sudden, infrequent, not
reasonably preventable'' and was not instead ``caused in part by poor
maintenance or careless operation.'' 40 CFR 60.2 (definition of
malfunction).
Finally, the EPA recognizes that even equipment that is properly
designed and maintained can sometimes fail. Such failure can sometimes
cause an exceedance of the relevant emission standard (See, e.g., State
Implementation Plans: Policy Regarding Excessive Emissions During
Malfunctions, Startup, and Shutdown (September 20, 1999); Policy on
Excess Emissions During Startup, Shutdown, Maintenance, and
Malfunctions (February 15, 1983)). The EPA is, therefore, proposing to
add an affirmative defense to civil penalties for exceedances of
emission limits that are caused by malfunctions. See 40 CFR 60.41Da
(defining ``affirmative defense'' to mean, in the context of an
enforcement proceeding, a response or defense put forward by a
defendant, regarding which the defendant has the burden of proof and
the merits of which are independently and objectively evaluated in a
judicial or administrative proceeding). We also are proposing other
regulatory provisions to specify the elements that are necessary to
establish this affirmative defense; the source must prove by a
preponderance of the evidence that it has met all of the elements set
forth in 40 CFR 60.46Da. (See 40 CFR 22.24). These criteria ensure that
the affirmative defense is available only where the event that causes
an exceedance of the emission limit meets the narrow definition of
malfunction in 40 CFR 60.2 (sudden, infrequent, not reasonably
preventable and not caused by poor maintenance and or careless
operation). For example, to successfully assert the affirmative
defense, the source must prove by a preponderance of the evidence that
excess emissions ``[w]ere caused by a sudden, infrequent, and
unavoidable failure of air pollution control and monitoring equipment,
process equipment, or a process to operate in a normal or usual manner
* * *'' The criteria also are designed to ensure that steps are taken
to correct the
[[Page 52767]]
malfunction, to minimize emissions in accordance with 40 CFR 60.40Da
and to prevent future malfunctions. For example, the source would have
to prove by a preponderance of the evidence that ``[r]epairs were made
as expeditiously as possible when the applicable emission limitations
were being exceeded * * *'' and that ``[a]ll possible steps were taken
to minimize the impact of the excess emissions on ambient air quality,
the environment and human health * * *'' In any judicial or
administrative proceeding, the Administrator may challenge the
assertion of the affirmative defense and, if the respondent has not met
the burden of proving all of the requirements in the affirmative
defense, appropriate penalties may be assessed in accordance with CAA
section 113 (see also 40 CFR part 22.77).
VII. Rationale for Proposed Action for NESHAP
A. What data were used for the NESHAP analyses?
To perform the technology review and residual risk analysis for the
two NESHAP, we created a comprehensive dataset (i.e., the MACT
dataset). This dataset was based on the EPA's 2005 National Emissions
Inventory (NEI). The NEI database contains information about sources
that emit criteria air pollutants and their precursors and HAP. The
database includes estimates of annual air pollutant emissions from
point, nonpoint and mobile sources in the 50 states, the District of
Columbia, Puerto Rico and the Virgin Islands. The EPA collects
information about sources and releases an updated version of the NEI
database every 3 years.
The NEI database is compiled from these primary sources:
Emissions inventories compiled by state and local
environmental agencies
Databases related to the EPA's MACT programs
Toxics Release Inventory data
For electric generating units, the EPA's Emission Tracking
System/CEM data and United States Department of Energy (DOE) fuel use
data
For onroad sources, the United States Federal Highway
Administration's estimate of vehicle miles traveled and emission
factors from the EPA's MOBILE computer model
For nonroad sources, the EPA's NONROAD computer model
Emissions inventories from previous years, if states do not
submit current data
To concentrate on only records pertaining to the oil and natural
gas industry sector, data were extracted using two criteria. First, we
specified that all facilities containing codes identifying the Oil and
Natural Gas Production and the Natural Gas Transmission and Storage
MACT source categories (MACT codes 0501 and 0504, respectively).
Second, we extracted facilities identified with the following NAICS
codes: 211 * * * (Oil and Gas Extraction), 221210 (Natural Gas
Distribution), 4861 * * * (Pipeline Transportation of Crude Oil), and
4862 * * * (Pipeline Transportation of Natural Gas). Once the data were
extracted, we reviewed the Source Classification Codes (SCC) to assess
whether there were any records included in the dataset that were
clearly not a part of the oil and natural gas sector. Our review of the
SCC also included assigning each SCC to an ``Emission Process Group''
that represents emission point types within the oil and natural gas
sector.
Since these MACT standards only apply to major sources, only
facilities designated as major sources in the NEI were extracted. In
the NEI, sources are identified as major if the facility-wide emissions
are greater than 10 tpy for any single HAP or 25 tpy for any
combination of HAP. We believe that this may overestimate the number of
major sources in the oil and natural gas sector because it does not
take into account the limitations set forth in the CAA regarding
aggregation of emissions from wells and associated equipment in
determining major source status.
The final dataset contained a total of 1,311 major sources in the
oil and natural gas sector; 990 in Oil and Natural Gas Production, and
321 in Natural Gas Transmission and Storage. To assess how
representative this number of facilities was, we obtained information
on the number of subject facilities for both MACT standards from the
Enforcement and Compliance History Online (ECHO) database. The ECHO
database is a web-based tool (http://www.epa-echo.gov/echo/index.html)
that provides public access to compliance and enforcement information
for approximately 800,000 EPA-regulated facilities. The ECHO database
allows users to find permit, inspection, violation, enforcement action
and penalty information covering the past 3 years. The site includes
facilities regulated as CAA stationary sources, as well as Clean Water
Act direct dischargers, and Resource Conservation and Recovery Act
hazardous waste generators/handlers. The data in the ECHO database are
updated monthly.
We performed a query on the ECHO database requesting records for
major sources, with NAICS codes 211*, 221210, 4861* and 4862*, with
information for MACT. The ECHO database query identified records for a
total of 555 facilities, 269 in the Oil and Natural Gas Production
source category (NAICS 211* and 221210) and 286 in the Natural Gas
Transmission and Storage source category (NAICS 4861* and 4862*). This
comparison leads us to conclude that, for the Natural Gas Transmission
and Storage segment, the NEI database is representative of the number
of sources subject to the rule. For the Oil and Natural Gas Production
source category, it confirms our assumption that the NEI dataset
contains more facilities than are subject to the rule. However, this
provides a conservative overestimate of the number of sources, which we
believe is appropriate for our risk analyses.
We are requesting that the public provide a detailed review of the
information in this dataset and provide comments and updated
information where appropriate. Section X of this preamble provides an
explanation of how to provide updated information for these datasets.
B. What are the proposed decisions regarding certain unregulated
emissions sources?
In addition to actions relative to the technology review and risk
reviews discussed below, we are proposing, pursuant to CAA sections
112(d)(2) and (3), MACT standards for glycol dehydrators and storage
vessels for which standards were not previously developed. We are also
proposing changes that affect the definition of ``associated
equipment'' which could apply these MACT standards to previously
unregulated sources.
1. Glycol Dehydrators
Once natural gas has been separated from any liquid materials or
products (e.g., crude oil, condensate or produced water), residual
entrained water is removed from the natural gas by dehydration.
Dehydration is necessary because water vapor may form hydrates, which
are ice-like structures, and can cause corrosion in or plug equipment
lines. The most widely used natural gas dehydration processes are
glycol dehydration and solid desiccant dehydration. Solid desiccant
dehydration, which is typically only used for lower throughputs, uses
adsorption to remove water and is not a source of HAP emissions.
[[Page 52768]]
Glycol dehydration is an absorption process in which a liquid
absorbent, glycol, directly contacts the natural gas stream and absorbs
any entrained water vapor in a contact tower or absorption column. The
majority of glycol dehydration units use triethylene glycol as the
absorbent, but ethylene glycol and diethylene glycol are also used. The
rich glycol, which has absorbed water vapor from the natural gas
stream, leaves the bottom of the absorption column and is directed
either to (1) a gas condensate glycol (GCG) separator (flash tank) and
then a reboiler or (2) directly to a reboiler where the water is boiled
off of the rich glycol. The regenerated glycol (lean glycol) is
circulated, by pump, into the absorption tower. The vapor generated in
the reboiler is directed to the reboiler vent.
The reboiler vent is a source of HAP emissions. In the glycol
contact tower, glycol not only absorbs water, but also absorbs selected
hydrocarbons, including BTEX and n-hexane. The hydrocarbons are boiled
off along with the water in the reboiler and vented to the atmosphere
or to a control device. The most commonly used control device is a
condenser. Condensers not only reduce emissions, but also recover
condensable hydrocarbon vapors that can be recovered and sold. In
addition, the dry non-condensable off-gas from the condenser may be
used as fuel or recycled into the production process or directed to a
flare, incinerator or other combustion device.
If present, the GCG separator (flash tank) is also a potential
source of HAP emissions. Some glycol dehydration units use flash tanks
prior to the reboiler to separate entrained gases, primarily methane
and ethane from the glycol. The flash tank off-gases are typically
recovered as fuel or recycled to the natural gas production header.
However, the flash tank may also be vented directly to the atmosphere.
Flash tanks typically enhance the reboiler condenser's emission
reduction efficiency by reducing the concentration of non-condensable
gases present in the stream prior to being introduced into the
condenser.
In the development of the MACT standards for the two oil and
natural gas source categories, the EPA created two subcategories of
glycol dehydrators based on actual annual average natural gas flowrate
and actual average benzene emissions. Under 40 CFR part 63, subpart HH,
(the Oil and Natural Gas Production NESHAP), the EPA established MACT
standards for glycol dehydration units with an actual annual average
natural gas flowrate greater than or equal to 85,000 scmd and actual
average benzene emissions greater than or equal to 0.90 Mg/yr (40 CFR
63.765(a)). The EPA did not establish standards for the other
subcategory, which consists of glycol dehydration units that are below
the flowrate and emission thresholds specified in subpart HH.
Similarly, under 40 CFR part 63, subpart HHH (the Natural Gas
Transmission and Storage NESHAP), the EPA established MACT standards
for the subcategory of glycol dehydration units with an actual annual
average natural gas flowrate greater than or equal to 283,000 scmd and
actual average benzene emissions greater than or equal to 0.90 Mg/yr,
but did not establish standards for the other subcategory, which
consists of glycol dehydration units that are below the flowrate and
emission thresholds specified in subpart HHH. As mentioned above, we
refer to these unregulated dehydration units in both subparts HH and
HHH as ``small dehydrators'' in this proposed rule.
The EPA is proposing emission standards for these subcategories of
small dehydrators (i.e., those dehydrators with an actual annual
average natural gas flowrate less than 85,000 scmd at production sites
or 283,000 scmd at natural gas transmission and storage sites, or
actual average benzene emissions less than 0.9 Mg/yr). Because we do
not have any new emissions data concerning these emission points, we
evaluated the dataset collected from industry during the development of
the original MACT standards (legacy docket A-94-04, item II-B-01, disk
1 for oil and natural gas production facilities; and items IV-G-24, 26,
27, 30 and 31 for natural gas transmission and storage facilities). We
believe this dataset is representative of currently operating glycol
dehydrators because it contains information for a varied group of
sources (i.e., units owned by different companies, located in different
states, representing a range of gas compositions and emission controls)
and that the processes have not changed significantly since the data
were collected.
In the Oil and Natural Gas Production source category, there were
91 glycol dehydration units with throughput and emissions data
identified that would be classified as small glycol dehydration units.
We evaluated the possibility of establishing a MACT floor as a Mg/yr
limit. However, due to variability of gas throughput and inlet gas
composition, we could not properly identify the best performing units
by only considering emissions. To allow us to normalize the emissions
for a more accurate determination of the best performing sources, we
created an emission factor in terms of grams BTEX/scm-ppmv for each
facility. The emission factor reflects the facility's emission level,
taking into consideration its natural gas throughput and inlet natural
gas BTEX concentration. To determine the MACT floor for the existing
dehydrators, we ranked each unit from lowest to highest, based on their
emission factor, to determine the facilities in the top 12 percent of
the dataset. The MACT floor was an emission factor of 1.10 x
10-4 grams BTEX/scm-ppmv. To meet this level of emissions,
we anticipate that sources will use a variety of options, including,
but not limited to, routing emissions to a condenser or to a combustion
device.
We also considered beyond-the-floor options for the existing
sources, as required by section 112(d)(2) of the CAA. To achieve
further reductions beyond the MACT floor level of control, sources
would have to install an additional add-on control device, most likely
a combustion device. Assuming the MACT floor control device is a
combustion device, which generally achieves at least a 95-percent HAP
reduction, then less than 5 percent of the initial HAP emissions
remain. Installing a second device would involve the same costs as the
first control, but would only achieve \1/20\ of the reduction (i.e.,
reducing the remaining 5 percent by another 95 percent represents a
4.49-percent reduction of the initial, uncontrolled emissions, which is
\1/20\ of the 95-percent reduction achieved with the first control).
Based on the $8,360/Mg cost effectiveness of the floor level of
control, we estimate that the incremental cost effectiveness of the
second control to be $167,200/Mg. We do not believe this cost to be
reasonable given the level of emission reduction. We are, therefore,
proposing an emission standard for existing small dehydrators that
reflects the MACT floor.
For new small glycol dehydrators in the Oil and Natural Gas
Production source category, based on our performance ranking, the best
performing source has an emission factor of 4.66 x 10-6
grams BTEX/scm-ppmv. To meet this level of emissions, we anticipate
that sources will use a variety of options, including, but not limited
to, routing emissions to a condenser or to a combustion device. The
consideration of beyond-the-floor options for new small dehydrators
would be the same as for existing small dehydrators, and, as stated
above, we do not believe a cost of $167,200/Mg to be reasonable given
the level of emission
[[Page 52769]]
reduction. We are, therefore, proposing a MACT standard for new small
dehydrators that reflects the MACT floor level of control.
Under our proposal, a small dehydrator's actual MACT emission limit
would be determined by multiplying the MACT floor emission factor in g
BTEX/scm-ppmv by its unit-specific incoming natural gas throughput and
BTEX concentration for the dehydrator. A formula is provided in 40 CFR
63.765(b)(1)(iii) to calculate the MACT limit as an annual value.
In the Natural Gas Transmission and Storage source category, there
were 16 facilities for which throughput and emissions data were
available that would be classified as small glycol dehydration units.
Since the number of units was less than 30, the MACT floor for existing
sources was based on the top five performing units. Using the same
emission factor concept, we determined that the MACT floor for existing
sources is an emission factor equal to 6.42 x 10-5 grams
BTEX/scm-ppmv. To meet this level of emissions, we anticipate that
sources will use a variety of options, including, but not limited to,
routing emissions to a condenser or to a combustion device.
We also considered beyond-the-floor options for the existing small
dehydrators as required by section 112(d)(2) of the CAA. To achieve
further reductions beyond the MACT floor level of control, sources
would have to install an additional add-on control device, most likely
a combustion device. Assuming the MACT floor control device is a
combustion device, which generally achieves at least a 95-percent HAP
reduction, then less than 5 percent of the initial HAP emissions
remain. Installing a second device would involve the same costs as the
first control device, but would only achieve \1/20\ of the reduction
(i.e., reducing the remaining 5 percent by another 95 percent
represents a 4.49-percent reduction of the initial, uncontrolled
emissions, which is \1/20\ of the 95-percent reduction achieved with
the first control). Based on the $1,650/Mg cost effectiveness of the
floor level of control, we estimate that the incremental cost
effectiveness of the second control to be $33,000/Mg. We do not believe
this cost to be reasonable given the level of emission reduction. We
are, therefore, proposing an emission standard for existing small
dehydrators that reflects the MACT floor.
For new small glycol dehydrators, based on our performance ranking,
the best performing source has an emission factor of 1.10 x
10-5 grams BTEX/scm-ppmv. To meet this level of emissions,
we anticipate that sources will use a variety of options, including,
but not limited to, routing emissions to a condenser or to a combustion
device. The consideration of beyond-the-floor options for new small
dehydrators would be the same as for existing small dehydrators, and,
as stated above, we do not believe a cost of $33,000/Mg to be
reasonable given the level of emission reduction. We are, therefore,
proposing an emission standard for new sources that reflects the MACT
floor level of control.
Under our proposal, a source's actual MACT emissions limit would be
determined by multiplying this emission factor by their unit-specific
incoming natural gas throughput and BTEX concentration for the
dehydrator. A formula is provided in 40 CFR 63.1275(b)(1)(iii) to
calculate the limit as an annual value.
As discussed below, we are proposing that, with the removal of the
1-ton alternative compliance option from the existing standards for
glycol dehydrators, the MACT for these two source categories would
provide an ample margin of safety to protect public health. We,
therefore, maintain that, after the implementation of the small
dehydrator standards discussed above, these MACT will continue to
provide an ample margin of safety to protect public health.
Consequently, we do not believe it will be necessary to conduct another
residual risk review under CAA section 112(f) for these two source
categories 8 years following promulgation of the small dehydrator
standards merely due to the addition of these new MACT requirements.
2. Storage Vessels
Crude oil, condensate and produced water are typically stored in
fixed-roof storage vessels. Some vessels used for storing produced
water may be open-top tanks. These vessels, which are operated at or
near atmospheric pressure conditions, are typically located at tank
batteries. A tank battery refers to the collection of process
components used to separate, treat and store crude oil, condensate,
natural gas and produced water. The extracted products from productions
wells enter the tank battery through the production header, which may
collect product from many wells.
Emissions from storage vessels are a result of working, breathing
and flash losses. Working losses occur due to the emptying and filling
of storage tanks. Breathing losses are the release of gas associated
with daily temperature fluctuations and other equilibrium effects.
Flash losses occur when a liquid with entrained gases is transferred
from a vessel with higher pressure to a vessel with lower pressure,
thus, allowing entrained gases or a portion of the liquid to vaporize
or flash. In the oil and natural gas production segment, flashing
losses occur when live crude oils or condensates flow into a storage
tank from a processing vessel operated at a higher pressure. Typically,
the larger the pressure drop, the more flashing emission will occur in
the storage stage. Temperature of the liquid may also influence the
amount of flash emissions.
In the Oil and Natural Gas Production NESHAP (40 CFR part 63,
subpart HH), the MACT standards for storage vessels apply only to those
with the PFE. Storage vessels with the PFE are defined as storage
vessels that contain hydrocarbon liquids that meet the following
criteria:
A stock tank gas to oil ratio (GOR) greater than or equal
to 0.31 cubic meters per liter (m\3\/liter); and
An American Petroleum Institute (API) gravity greater than
or equal to 40 degrees; and
An actual annual average hydrocarbon liquid throughput
greater than or equal to 79,500 liters per day (liter/day).
Accordingly, there is no emission limit in the existing MACT for
storage vessels without the PFE. However, the MACT analysis performed
at the time indicates that the MACT floor was based on all storage
vessels, not just those vessels with flash emissions. See,
Recommendation of MACT Floor Levels for HAP Emission Points at Major
Sources in the Oil and Natural Gas Production Source Category,
(September 23, 1997, Docket A-94-04, Item II-A-07). We, therefore,
propose to apply the existing MACT for storage vessels with PFE to all
storage vessels (i.e., storage vessels with the PFE, as well as those
without the PFE).
3. Definition of Associated Equipment
CAA section 112(n)(4)(A) provides:
Notwithstanding the provisions of subsection (a), emissions from
any oil or gas exploration or production well (with its associated
equipment) and emission from any pipeline compressor or pump station
shall not be aggregated with emissions from other similar units,
whether or not such units are in contiguous area or under common
control, to determine whether such units or stations are major
sources.
As stated above, the CAA prevents aggregation of HAP emissions from
wells and associated equipment in making major source determinations.
In the absence of clear guidance in the statute on what constitutes
``associated equipment,'' the EPA sought to define
[[Page 52770]]
``associated equipment'' in a way that recognizes the need to implement
relief for this industry as Congress intended and that also allow for
the appropriate regulation of significant emission points. 64 FR at
32619. Accordingly, in the existing Oil and Natural Gas Production
NESHAP (1998 and 1999 NESHAP), the EPA defined ``associated equipment''
to exclude glycol dehydration units and storage vessels with PFE (thus
allowing their emissions to be included in determining major source
status) because EPA identified these sources as substantial
contributors to HAP emissions. Id. EPA explained in that NESHAP that,
because a single storage vessel with flash emissions may emit several
Mg of HAP per year and individual glycol dehydrators may emit above the
major source level, storage vessels with PFE and glycol dehydrators are
large individual sources of HAP, 63 FR 6288, 6301 (1998). The EPA
therefore considered these emission sources substantial contributors to
HAP emissions and excluded them from the definition of ``associated
equipment.'' 64 FR at 32619. We have recently examined HAP emissions
from storage vessels without flash emissions and found that these
emissions are significant and comparable to those vessels with flash
emissions. For example, one storage vessel with an API gravity of 30
degrees and a GOR of 2.09 x 10-3 m\3\/liter with a
throughput of 79,500 liter/day had HAP emissions of 9.91 Mg/yr,
including 9.45 Mg/yr of n-hexane.
Because storage vessels without the PFE can have significant
emissions at levels that are comparable to emissions from storage
vessels with the PFE, there is no appreciable difference between
storage vessels with the PFE and those without the PFE for purposes of
defining ``associated equipment.'' We are, therefore, proposing to
amend the associated equipment definition to exclude all storage
vessels and not just storage vessels with the PFE.
C. How did we perform the risk assessment and what are the results and
proposed decisions?
1. How did we estimate risks posed by the source categories?
The EPA conducted risk assessments that provided estimates for each
source in a category of the MIR posed by the HAP emissions, the HI for
chronic exposures to HAP with the potential to cause noncancer health
effects, and the hazard quotient (HQ) for acute exposures to HAP with
the potential to cause noncancer health effects. The assessments also
provided estimates of the distribution of cancer risks within the
exposed populations, cancer incidence and an evaluation of the
potential for adverse environmental effects for each source category.
The risk assessments consisted of seven primary steps, as discussed
below. The docket for this rulemaking contains the following document
which provides more information on the risk assessment inputs and
models: Draft Residual Risk Assessment for the Oil and Gas Production
and Natural Gas Transmission and Storage Source Categories. The methods
used to assess risks (as described in the seven primary steps below)
are consistent with those peer-reviewed by a panel of the EPA's Science
Advisory Board (SAB) in 2009 and described in their peer review report
issued in 2010 \14\; they are also consistent with the key
recommendations contained in that report.
---------------------------------------------------------------------------
\14\ U.S. EPA SAB. Risk and Technology Review (RTR) Risk
Assessment Methodologies: For Review by the EPA's Science Advisory
Board with Case Studies--MACT I Petroleum Refining Sources and
Portland Cement Manufacturing, May 2010.
---------------------------------------------------------------------------
a. Establishing the Nature and Magnitude of Actual Emissions and
Identifying the Emissions Release Characteristics
As discussed in section VII.A of this preamble, we used a dataset
based on the 2005 NEI as the basis for the risk assessment. In addition
to the quality assurance (QA) of the facilities contained in the
dataset, we also checked the coordinates of every facility in the
dataset through visual observations using tools such as GoogleEarth and
ArcView. Where coordinates were found to be incorrect, we identified
and corrected them to the extent possible. We also performed QA of the
emissions data and release characteristics to ensure there were no
outliers.
b. Establishing the Relationship Between Actual Emissions and MACT-
Allowable Emissions Levels
The available emissions data in the MACT dataset represent the
estimates of mass of emissions actually emitted during the specified
annual time period. These ``actual'' emission levels are often lower
than the emission levels that a facility might be allowed to emit and
still comply with the MACT standards. The emissions level allowed to be
emitted by the MACT standards is referred to as the ``MACT-allowable''
emissions level. This represents the highest emissions level that could
be emitted by the facility without violating the MACT standards.
We discussed the use of both MACT-allowable and actual emissions in
the final Coke Oven Batteries residual risk rule (70 FR 19998-19999,
April 15, 2005) and in the proposed and final Hazardous Organic NESHAP
residual risk rules (71 FR 34428, June 14, 2006, and 71 FR 76609,
December 21, 2006, respectively). In those previous actions, we noted
that assessing the risks at the MACT-allowable level is inherently
reasonable since these risks reflect the maximum level sources could
emit and still comply with national emission standards. But we also
explained that it is reasonable to consider actual emissions, where
such data are available, in both steps of the risk analysis, in
accordance with the Benzene NESHAP. (54 FR 38044, September 14, 1989.)
To estimate emissions at the MACT-allowable level, we developed a
ratio of MACT-allowable to actual emissions for each emissions source
type in each source category, based on the level of control required by
the MACT standards compared to the level of reported actual emissions
and available information on the level of control achieved by the
emissions controls in use.
c. Conducting Dispersion Modeling, Determining Inhalation Exposures and
Estimating Individual and Population Inhalation Risks
Both long-term and short-term inhalation exposure concentrations
and health risks from each source in the source categories addressed in
this proposal were estimated using the Human Exposure Model (HEM)
(Community and Sector HEM-3 version 1.1.0). The HEM-3 performs three
primary risk assessment activities: (1) Conducting dispersion modeling
to estimate the concentrations of HAP in ambient air, (2) estimating
long-term and short-term inhalation exposures to individuals residing
within 50 km of the modeled sources and (3) estimating individual and
population-level inhalation risks using the exposure estimates and
quantitative dose-response information.
The dispersion model used by HEM-3 is AERMOD, which is one of the
EPA's preferred models for assessing pollutant concentrations from
industrial facilities.\15\ To perform the dispersion modeling and to
develop the preliminary risk estimates, HEM-3 draws on three data
libraries. The first is a library of meteorological data,
[[Page 52771]]
which is used for dispersion calculations. This library includes 1 year
of hourly surface and upper air observations for more than 158
meteorological stations, selected to provide coverage of the United
States and Puerto Rico. A second library of United States Census Bureau
census block \16\ internal point locations and populations provides the
basis of human exposure calculations (Census, 2000). In addition, for
each census block, the census library includes the elevation and
controlling hill height, which are also used in dispersion
calculations. A third library of pollutant unit risk factors and other
health benchmarks is used to estimate health risks. These risk factors
and health benchmarks are the latest values recommended by the EPA for
HAP and other toxic air pollutants. These values are available at
http://www.epa.gov/ttn/atw/toxsource/summary.html and are discussed in
more detail later in this section.
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\15\ U.S. EPA. Revision to the Guideline on Air Quality Models:
Adoption of a Preferred General Purpose (Flat and Complex Terrain)
Dispersion Model and Other Revisions (70 FR 68218, November 9,
2005).
\16\ A census block is generally the smallest geographic area
for which census statistics are tabulated.
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In developing the risk assessment for chronic exposures, we used
the estimated annual average ambient air concentration of each of the
HAP emitted by each source for which we have emissions data in the
source category. The air concentrations at each nearby census block
centroid were used as a surrogate for the chronic inhalation exposure
concentration for all the people who reside in that census block. We
calculated the MIR for each facility as the cancer risk associated with
a continuous lifetime (24 hours per day, 7 days per week, and 52 weeks
per year for a 70-year period) exposure to the maximum concentration at
the centroid of an inhabited census block. Individual cancer risks were
calculated by multiplying the estimated lifetime exposure to the
ambient concentration of each of the HAP (in micrograms per cubic
meter) by its unit risk estimate (URE), which is an upper bound
estimate of an individual's probability of contracting cancer over a
lifetime of exposure to a concentration of 1 microgram of the pollutant
per cubic meter of air. For residual risk assessments, we generally use
URE values from the EPA's Integrated Risk Information System (IRIS).
For carcinogenic pollutants without the EPA IRIS values, we look to
other reputable sources of cancer dose-response values, often using
California EPA (CalEPA) URE values, where available. In cases where
new, scientifically credible dose-response values have been developed
in a manner consistent with the EPA guidelines and have undergone a
peer review process similar to that used by the EPA, we may use such
dose-response values in place of or in addition to other values, if
appropriate.
Formaldehyde is a unique case. In 2004, the EPA determined that the
Chemical Industry Institute of Toxicology (CIIT) cancer dose-response
value for formaldehyde (5.5 x 10-\9\ per [mu]g/m\3\) was
based on better science than the IRIS cancer dose-response value (1.3 x
10-\5\ per [mu]g/m\3\) and we switched from using the IRIS
value to the CIIT value in risk assessments supporting regulatory
actions. However, subsequent research published by the EPA suggests
that the CIIT model was not appropriate and in 2010 the EPA returned to
using the 1991 IRIS value, which is more health protective.\17\ The EPA
has been working on revising the formaldehyde IRIS assessment and the
National Academy of Sciences (NAS) completed its review of the EPA's
draft in May of 2011. EPA is reviewing the public comments and the NAS
independent scientific peer review, and the draft IRIS assessment will
be revised and the final assessment will be posted on the IRIS
database. In the interim, we will present findings using the 1991 IRIS
value as a primary estimate, and may also consider other information as
the science evolves.
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\17\ For details on the justification for this decision, see the
memorandum in the docket from Peter Preuss to Steve Page entitled,
Recommendation for Formaldehyde Inhalation Cancer Risk Values,
January 22, 2010.
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In the case of benzene, the high end of the reported cancer URE
range was used in our assessments to provide a conservative estimate of
potential cancer risks. Use of the high end of the range provides risk
estimates that are approximately 3.5 times higher than use of the
equally-plausible low end value. We also evaluated the impact of using
the low end of the URE range on our risk results.
We also note that polycyclic organic matter (POM), a carcinogenic
HAP with a mutagenic mode of action, is emitted by some of the
facilities in these two categories.\18\ For this compound group,\19\
the age-dependent adjustment factors (ADAF) described in the EPA's
Supplemental Guidance for Assessing Susceptibility from Early-Life
Exposure to Carcinogens \20\ were applied. This adjustment has the
effect of increasing the estimated lifetime risks for POM by a factor
of 1.6. In addition, although only a small fraction of the total POM
emissions were not reported as individual compounds, the EPA expresses
carcinogenic potency for compounds in this group in terms of
benzo[a]pyrene equivalence, based on evidence that carcinogenic POM has
the same mutagenic mechanism of action as benzo[a]pyrene. For this
reason, the EPA's Science Policy Council \21\ recommends applying the
Supplemental Guidance to all carcinogenic polycyclic aromatic
hydrocarbons for which risk estimates are based on relative potency.
Accordingly, we have applied the ADAF to the benzo[a]pyrene equivalent
portion of all POM mixtures.
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\18\ U.S. EPA. Performing risk assessments that include
carcinogens described in the Supplemental Guidance as having a
mutagenic mode of action. Science Policy Council Cancer Guidelines
Implementation Work Group Communication II: Memo from W.H. Farland,
dated October 4, 2005.
\19\ See the Risk Assessment for Source Categories document
available in the docket for a list of HAP with a mutagenic mode of
action.
\20\ U.S. EPA. Supplemental Guidance for Assessing Early-Life
Exposure to Carcinogens. EPA/630/R-03/003F, 2005. http://www.epa.gov/ttn/atw/childrens_supplement_final.pdf.
\21\ U.S. EPA. Science Policy Council Cancer Guidelines
Implementation Workgroup Communication II: Memo from W.H. Farland,
dated June 14, 2006.
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Incremental individual lifetime cancer risks associated with
emissions from the source category were estimated as the sum of the
risks for each of the carcinogenic HAP (including those classified as
carcinogenic to humans, likely to be carcinogenic to humans and
suggestive evidence of carcinogenic potential \22\) emitted by the
modeled source. Cancer incidence and the distribution of individual
cancer risks for the population within 50 km of any source were also
estimated for the source category as part of these assessments by
summing individual risks. A distance of 50 km is consistent with both
the analysis supporting the 1989 Benzene NESHAP (54 FR 38044) and the
limitations of Gaussian dispersion models, including AERMOD.
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\22\ These classifications also coincide with the terms ``known
carcinogen, probable carcinogen and possible carcinogen,''
respectively, which are the terms advocated in the EPA's previous
Guidelines for Carcinogen Risk Assessment, published in 1986 (51 FR
33992, September 24, 1986). Summing the risks of these individual
compounds to obtain the cumulative cancer risks is an approach that
was recommended by the EPA's SAB in their 2002 peer review of EPA's
NATA entitled, NATA--Evaluating the National-scale Air Toxics
Assessment 1996 Data--an SAB Advisory, available at: http://
yosemite.epa.gov/sab/sabproduct.nsf/
214C6E915BB04E14852570CA007A682C/$File/ecadv02001.pdf.
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To assess risk of noncancer health effects from chronic exposures,
we summed the HQ for each of the HAP that affects a common target organ
system to obtain the HI for that target organ system (or target organ-
specific HI, TOSHI). The HQ for chronic exposures is the estimated
chronic
[[Page 52772]]
exposure divided by the chronic reference level, which is either the
EPA reference concentration (RfC), defined as ``an estimate (with
uncertainty spanning perhaps an order of magnitude) of a continuous
inhalation exposure to the human population (including sensitive
subgroups) that is likely to be without an appreciable risk of
deleterious effects during a lifetime,'' or, in cases where an RfC from
the EPA's IRIS database is not available, the EPA will utilize the
following prioritized sources for our chronic dose-response values: (1)
The Agency for Toxic Substances and Disease Registry Minimum Risk
Level, which is defined as ``an estimate of daily human exposure to a
substance that is likely to be without an appreciable risk of adverse
effects (other than cancer) over a specified duration of exposure'';
(2) the CalEPA Chronic Reference Exposure Level (REL), which is defined
as ``the concentration level at or below which no adverse health
effects are anticipated for a specified exposure duration''; and (3),
as noted above, in cases where scientifically credible dose-response
values have been developed in a manner consistent with the EPA
guidelines and have undergone a peer review process similar to that
used by the EPA, we may use those dose-response values in place of or
in concert with other values.
Screening estimates of acute exposures and risks were also
evaluated for each of the HAP at the point of highest off-site exposure
for each facility (i.e., not just the census block centroids), assuming
that a person is located at this spot at a time when both the peak
(hourly) emission rate and worst-case dispersion conditions (1991
calendar year data) occur. The acute HQ is the estimated acute exposure
divided by the acute dose-response value. In each case, acute HQ values
were calculated using best available, short-term dose-response values.
These acute dose-response values, which are described below, include
the acute REL, acute exposure guideline levels (AEGL) and emergency
response planning guidelines (ERPG) for 1-hour exposure durations. As
discussed below, we used conservative assumptions for emission rates,
meteorology and exposure location for our acute analysis.
As described in the CalEPA's Air Toxics Hot Spots Program Risk
Assessment Guidelines, Part I, The Determination of Acute Reference
Exposure Levels for Airborne Toxicants, an acute REL value (http://www.oehha.ca.gov/air/pdf/acuterel.pdf) is defined as ``the
concentration level at or below which no adverse health effects are
anticipated for a specified exposure duration.'' Acute REL values are
based on the most sensitive, relevant, adverse health effect reported
in the medical and toxicological literature. Acute REL values are
designed to protect the most sensitive individuals in the population by
the inclusion of margins of safety. Since margins of safety are
incorporated to address data gaps and uncertainties, exceeding the
acute REL does not automatically indicate an adverse health impact.
AEGL values were derived in response to recommendations from the
National Research Council (NRC). As described in Standing Operating
Procedures (SOP) of the National Advisory Committee on Acute Exposure
Guideline Levels for Hazardous Substances (http://www.epa.gov/opptintr/aegl/pubs/sop.pdf),\23\ ``the NRC's previous name for acute exposure
levels--community emergency exposure levels--was replaced by the term
AEGL to reflect the broad application of these values to planning,
response, and prevention in the community, the workplace,
transportation, the military, and the remediation of Superfund sites.''
This document also states that AEGL values ``represent threshold
exposure limits for the general public and are applicable to emergency
exposures ranging from 10 minutes to eight hours.'' The document lays
out the purpose and objectives of AEGL by stating (page 21) that ``the
primary purpose of the AEGL program and the National Advisory Committee
for Acute Exposure Guideline Levels for Hazardous Substances is to
develop guideline levels for once-in-a-lifetime, short-term exposures
to airborne concentrations of acutely toxic, high-priority chemicals.''
In detailing the intended application of AEGL values, the document
states (page 31) that ``[i]t is anticipated that the AEGL values will
be used for regulatory and nonregulatory purposes by U.S. Federal and
state agencies and possibly the international community in conjunction
with chemical emergency response, planning, and prevention programs.
More specifically, the AEGL values will be used for conducting various
risk assessments to aid in the development of emergency preparedness
and prevention plans, as well as real-time emergency response actions,
for accidental chemical releases at fixed facilities and from transport
carriers.''
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\23\ NAS, 2001. Standing Operating Procedures for Developing
Acute Exposure Levels for Hazardous Chemicals, page 2.
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The AEGL-1 value is then specifically defined as ``the airborne
concentration of a substance above which it is predicted that the
general population, including susceptible individuals, could experience
notable discomfort, irritation, or certain asymptomatic nonsensory
effects. However, the effects are not disabling and are transient and
reversible upon cessation of exposure.'' The document also notes (page
3) that, ``Airborne concentrations below AEGL-1 represent exposure
levels that can produce mild and progressively increasing but transient
and nondisabling odor, taste, and sensory irritation or certain
asymptomatic, nonsensory effects.'' Similarly, the document defines
AEGL-2 values as ``the airborne concentration (expressed as ppm or mg/
m\3\) of a substance above which it is predicted that the general
population, including susceptible individuals, could experience
irreversible or other serious, long-lasting adverse health effects or
an impaired ability to escape.''
ERPG values are derived for use in emergency response, as described
in the American Industrial Hygiene Association's document entitled,
Emergency Response Planning Guidelines (ERPG) Procedures and
Responsibilities (http://www.aiha.org/1documents/committees/ERPSOPs2006.pdf) which states that, ``Emergency Response Planning
Guidelines were developed for emergency planning and are intended as
health based guideline concentrations for single exposures to
chemicals.'' \24\ The ERPG-1 value is defined as ``the maximum airborne
concentration below which it is believed that nearly all individuals
could be exposed for up to 1 hour without experiencing other than mild
transient adverse health effects or without perceiving a clearly
defined, objectionable odor.'' Similarly, the ERPG-2 value is defined
as ``the maximum airborne concentration below which it is believed that
nearly all individuals could be exposed for up to 1 hour without
experiencing or developing irreversible or other serious health effects
or symptoms which could impair an individual's ability to take
protective action.''
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\24\ ERP Committee Procedures and Responsibilities. November 1,
2006. American Industrial Hygiene Association.
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As can be seen from the definitions above, the AEGL and ERPG values
include the similarly-defined severity levels 1 and 2. For many
chemicals, a severity level 1 value AEGL or ERPG has not been
developed; in these instances, higher severity level AEGL-2 or ERPG-2
values are compared to our modeled
[[Page 52773]]
exposure levels to screen for potential acute concerns.
Acute REL values for 1-hour exposure durations are typically lower
than their corresponding AEGL-1 and ERPG-1 values. Even though their
definitions are slightly different, AEGL-1 values are often the same as
the corresponding ERPG-1 values, and AEGL-2 values are often equal to
ERPG-2 values. Maximum HQ values from our acute screening risk
assessments typically result when basing them on the acute REL value
for a particular pollutant. In cases where our maximum acute HQ value
exceeds 1, we also report the HQ value based on the next highest acute
dose-response value (usually the AEGL-1 and/or the ERPG-1 value).
To develop screening estimates of acute exposures, we developed
estimates of maximum hourly emission rates by multiplying the average
actual annual hourly emission rates by a factor to cover routinely
variable emissions. We chose the factor based on process knowledge and
engineering judgment and with awareness of a Texas study of short-term
emissions variability, which showed that most peak emission events, in
a heavily-industrialized 4-county area (Harris, Galveston, Chambers and
Brazoria Counties, Texas) were less than twice the annual average
hourly emission rate. The highest peak emission event was 74 times the
annual average hourly emission rate, and the 99th percentile ratio of
peak hourly emission rate to the annual average hourly emission rate
was 9.\25\ This analysis is provided in Appendix 4 of the Draft
Residual Risk Assessment for the Oil and Gas Production and Natural Gas
Transmission and Storage Source Categories, which is available in the
docket for this action. Considering this analysis, unless specific
process knowledge or data are available to provide an alternate value,
to account for more than 99 percent of the peak hourly emissions, we
apply a conservative screening multiplication factor of 10 to the
average annual hourly emission rate in these acute exposure screening
assessments. The factor of 10 was used for both the Oil and Natural Gas
Production and the Natural Gas Transmission and Storage source
categories.
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\25\ See http://www.tceq.state.tx.us/compliance/field_ops/eer/index.html or docket to access the source of these data.
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In cases where acute HQ values from the screening step were less
than or equal to 1, acute impacts were deemed negligible and no further
analysis was performed. In cases where an acute HQ from the screening
step was greater than 1, additional site-specific data were considered
to develop a more refined estimate of the potential for acute impacts
of concern. The data refinements employed for these source categories
consisted of using the site-specific facility layout to distinguish
facility property from an area where the public could be exposed. These
refinements are discussed in the draft risk assessment document, which
is available in the docket for each of these source categories.
Ideally, we would prefer to have continuous measurements over time to
see how the emissions vary by each hour over an entire year. Having a
frequency distribution of hourly emission rates over a year would allow
us to perform a probabilistic analysis to estimate potential threshold
exceedances and their frequency of occurrence. Such an evaluation could
include a more complete statistical treatment of the key parameters and
elements adopted in this screening analysis. However, we recognize that
having this level of data is rare, hence our use of the multiplier
approach.
To better characterize the potential health risks associated with
estimated acute exposures to HAP, and in response to a key
recommendation from the SAB's peer review of the EPA's RTR risk
assessment methodologies,\26\ we generally examine a wider range of
available acute health metrics than we do for our chronic risk
assessments. This is in response to the SAB's acknowledgement that
there are generally more data gaps and inconsistencies in acute
reference values than there are in chronic reference values.
Comparisons of the estimated maximum off-site 1-hour exposure levels
are not typically made to occupational levels for the purpose of
characterizing public health risks in RTR assessments. This is because
they are developed for working age adults and are not generally
considered protective for the general public. We note that occupational
ceiling values are, for most chemicals, set at levels higher than a 1-
hour AEGL-1.
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\26\ The SAB peer review of RTR Risk Assessment Methodologies is
available at: http://yosemite.epa.gov/sab/sabproduct.nsf/
4AB3966E263D943A8525771F00668381/$File/EPA-SAB-10-007-unsigned.pdf.
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As discussed in section VII.C.2 of this preamble, the maximum
estimated worst-case 1-hour exposure to benzene outside the facility
fence line for a facility in either source category is 12 mg/m\3\. This
estimated exposure exceeds the 6-hour REL by a factor of 9
(HQREL = 9), but is significantly below the 1-hour AEGL-1
(HQAEGL-1 = 0.07). Although this worst-case exposure
estimate does not exceed the AEGL-1, we note here that it slightly
exceeds workplace ceiling level guidelines designed to protect the
worker population for short duration (<15 minute) increases in exposure
to benzene, as discussed below. The occupational short-term exposure
limit (STEL) standard for benzene developed by the Occupational Safety
and Health Administration is 16 mg/m\3\, ``as averaged over any 15-
minute period.'' \27\ Occupational guideline STEL for exposures to
benzene have also been developed by the American Conference of
Governmental Industrial Hygienists (ACGIH) \28\ for less than 15
minutes \29\ (ACGIH threshold limit value (TLV)-STEL value of 8.0 mg/
m\3\), and by the National Institute for Occupational Safety and Health
(NIOSH) \30\ ``for any 15 minute period in a work day'' (NIOSH REL-STEL
of 3.2 mg/m\3\). These shorter duration occupational values indicate
potential concerns regarding health effects at exposure levels below
the 1-hour AEGL-1 value. We solicit comment on the use of the
occupational values described above in the interpretation of these
worst-case acute screening exposure estimates.
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\27\ 29 CFR 1910.1028, Benzene. Available online at http://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=STANDARDS&p_id=10042.
\28\ ACGIH (2001) Benzene. In Documentation of the TLVs[supreg]
and BEIs[supreg] with Other Worldwide Occupational Exposure Values.
ACGIH, 1300 Kemper Meadow Drive, Cincinnati, OH 45240 (ISBN: 978-1-
882417-74-2) and available online at http://www.acgih.org.
\29\ The ACGIH definition of a TLV-STEL states that ``Exposures
above the TLV-TWA up to the TLV-STEL should be less than 15 minutes,
should occur no more than four times per day, and there should be at
least 60 minutes between successive exposures in this range.''
\30\ NIOSH. Occupational Safety and Health Guideline for
Benzene; http://www.cdc.gov/niosh/74-137.html.
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d. Conducting Multi-Pathway Exposure and Risk Modeling
The potential for significant human health risks due to exposures
via routes other than inhalation (i.e., multi-pathway exposures) and
the potential for adverse environmental impacts were evaluated in a
three-step process. In the first step, we determined whether any
facilities emitted any HAP known to be PB-HAP (HAP known to be
persistent and bio-accumulative) in the environment. There are 14 PB-
HAP compounds or compound classes identified for this screening in the
EPA's Air Toxics Risk Assessment Library (available at http://www.epa.gov/ttn/fera/risk_atra_vol1.html). They are cadmium
compounds, chlordane, chlorinated dibenzodioxins and furans,
[[Page 52774]]
dichlorodiphenyldichloroethylene, heptachlor, hexachlorobenzene,
hexachlorocyclohexane, lead compounds, mercury compounds, methoxychlor,
polychlorinated biphenyls, POM, toxaphene and trifluralin.
Since one or more of these PB-HAP are emitted by at least one
facility in both source categories, we proceeded to the second step of
the evaluation. In this step, we determined whether the facility-
specific emission rates of each of the emitted PB-HAP were large enough
to create the potential for significant non-inhalation human or
environmental risks under reasonable worst-case conditions. To
facilitate this step, we have developed emission rate thresholds for
each PB-HAP using a hypothetical worst-case screening exposure scenario
developed for use in conjunction with the EPA's TRIM.FaTE model. The
hypothetical screening scenario was subjected to a sensitivity analysis
to ensure that its key design parameters were established such that
environmental media concentrations were not underestimated (i.e., to
minimize the occurrence of false negatives or results that suggest that
risks might be acceptable when, in fact, actual risks are high) and to
also minimize the occurrence of false positives for human health
endpoints. We call this application of the TRIM.FaTE model TRIM-Screen.
The facility-specific emission rates of each of the PB-HAP in each
source category were compared to the TRIM-Screen emission threshold
values for each of the PB-HAP identified in the source category
datasets to assess the potential for significant human health risks or
environmental risks via non-inhalation pathways.
There was only one facility in the Natural Gas Transmission and
Storage source category with reported emissions of PB-HAP, and the
emission rates were less than the emission threshold values. There were
29 facilities in the Oil and Natural Gas Production source category
with reported emissions of PB-HAP, and one of these had emission rates
greater than the emission threshold values. In this case, the emission
threshold value for POM was exceeded by a factor of 6. For POM, dairy,
vegetables and fruits were the three most dominant exposure pathways
driving human exposures in the hypothetical screening exposure
scenario. The single facility with emissions exceeding the emission
threshold value for POM is located in a highly industrialized area.
Therefore, since the exposure pathways which would drive high human
exposure are not locally available, multi-pathway exposures and
environmental risks were deemed negligible, and no further analysis was
performed. For further information on the multi-pathway analysis
approach, see the residual risk documentation.
e. Assessing Risks Considering Emissions Control Options
In addition to assessing baseline inhalation risks and screening
for potential multi-pathway risks, where appropriate, we also estimated
risks considering the potential emission reductions that would be
achieved by the particular control options under consideration. In
these cases, the expected emissions reductions were applied to the
specific HAP and emissions sources in the source category dataset to
develop corresponding estimates of risk reductions.
f. Conducting Other Risk-Related Analyses: Facility-Wide Assessments
To put the source category risks in context, we also examined the
risks from the entire ``facility,'' where the facility includes all
HAP-emitting operations within a contiguous area and under common
control. In other words, for each facility that includes one or more
sources from one of the source categories under review, we examined the
HAP emissions not only from the source category of interest, but also
from all other emission sources at the facility. The emissions data for
generating these ``facility-wide'' risks were also obtained from the
2005 NEI. For every facility included in the MACT database, we also
retrieved emissions data and release characteristics for all other
emission sources at the same facility. We estimated the risks due to
the inhalation of HAP that are emitted ``facility-wide'' for the
populations residing within 50 km of each facility, consistent with the
methods used for the source category analysis described above. For
these facility-wide risk analyses, the modeled source category risks
were compared to the facility-wide risks to determine the portion of
facility-wide risks that could be attributed to the source categories
addressed in this proposal. We specifically examined the facilities
associated with the highest estimates of risk and determined the
percentage of that risk attributable to the source category of
interest. The risk documentation available through the docket for this
action provides the methodology and the results of the facility-wide
analyses for each source category.
g. Conducting Other Analyses: Demographic Analysis
To examine the potential for any environmental justice (EJ) issues
that might be associated with each source category, we performed a
demographic analysis of population risk. In this analysis, we evaluated
the distributions of HAP-related cancer and noncancer risks across
different social, demographic and economic groups within the
populations living near the facilities where these source categories
are located. The development of demographic analyses to inform the
consideration of EJ issues in the EPA rulemakings is an evolving
science. The EPA offers the demographic analyses in this rulemaking to
inform the consideration of potential EJ issues and invites public
comment on the approaches used and the interpretations made from the
results, with the hope that this will support the refinement and
improve the utility of such analyses for future rulemakings.
For the demographic analyses, we focus on the populations within 50
km of any facility estimated to have exposures to HAP which result in
cancer risks of 1-in-1 million or greater, or noncancer HI of 1 or
greater (based on the emissions of the source category or the facility,
respectively). We examine the distributions of those risks across
various demographic groups, comparing the percentages of particular
demographic groups to the total number of people in those demographic
groups nationwide. The results, including other risk metrics, such as
average risks for the exposed populations, are documented in source-
category-specific technical reports in the docket for both source
categories covered in this proposal.
The basis for the risk values used in these analyses were the
modeling results based on actual emissions levels obtained from the
HEM-3 model described above. The risk values for each census block were
linked to a database of information from the 2000 Decennial census that
includes data on race and ethnicity, age distributions, poverty status,
household incomes and education level. The Census Department
Landview[supreg] database was the source of the data on race and
ethnicity and the data on age distributions, poverty status, household
incomes and education level were obtained from the 2000 Census of
Population and Housing Summary File 3 Long Form. While race and
ethnicity census data are available at the census block level, the age
and income census data are only available at the census block group
level (which includes an
[[Page 52775]]
average of 26 blocks or an average of 1,350 people). Where census data
are available at the block group level, but not the block level, we
assumed that all census blocks within the block group have the same
distribution of ages and incomes as the block group.
For each source category, we focused on those census blocks where
source category risk results show estimated lifetime inhalation cancer
risks above 1-in-1 million or chronic noncancer indices above 1 and
determined the relative percentage of different racial and ethnic
groups, different age groups, adults with and without a high school
diploma, people living in households below the national median income
and for people living below the poverty line within those census
blocks. The specific census population categories studied include:
Total population
White
African American (or Black)
Native Americans
Other races and multiracial
Hispanic or Latino
Children 18 years of age and under
Adults 19 to 64 years of age
Adults 65 years of age and over
Adults without a high school diploma
Households earning under the national median income
People living below the poverty line
It should be noted that these categories overlap in some instances,
resulting in some populations being counted in more than one category
(e.g., other races and multiracial and Hispanic). In addition, while
not a specific census population category, we also examined risks to
``Minorities,'' a classification which is defined for these purposes as
all race population categories except white.
For further information about risks to the populations located near
the facilities in these source categories, we also evaluated the
estimated distribution of inhalation cancer and chronic noncancer risks
associated with the HAP emissions from all the emissions sources at the
facility (i.e., facility-wide). This analysis used the facility-wide
RTR modeling results and the census data described above.
The methodology and the results of the demographic analyses for
each source category are included in a source-category-specific
technical report for each of the categories, which are available in the
docket for this action.
h. Considering Uncertainties in Risk Assessment
Uncertainty and the potential for bias are inherent in all risk
assessments, including those performed for the source categories
addressed in this proposal. Although uncertainty exists, we believe
that our approach, which used conservative tools and assumptions,
ensures that our decisions are health-protective. A brief discussion of
the uncertainties in the emissions datasets, dispersion modeling,
inhalation exposure estimates and dose-response relationships follows
below. A more thorough discussion of these uncertainties is included in
the risk assessment documentation (referenced earlier) available in the
docket for this action.
i. Uncertainties in the Emissions Datasets
Although the development of the MACT dataset involved QA/quality
control processes, the accuracy of emissions values will vary depending
on the source of the data, the degree to which data are incomplete or
missing, the degree to which assumptions made to complete the datasets
are inaccurate, errors in estimating emissions values and other
factors. The emission estimates considered in this analysis generally
are annual totals for certain years that do not reflect short-term
fluctuations during the course of a year or variations from year to
year.
The estimates of peak hourly emission rates for the acute effects
screening assessment were based on a multiplication factor of 10
applied to the average annual hourly emission rate, which is intended
to account for emission fluctuations due to normal facility operations.
Additionally, although we believe that we have data for most facilities
in these two source categories in our RTR dataset, our dataset may not
include data for all existing facilities. Moreover, there are
uncertainties with regard to the identification of sources as major or
area in the NEI for these source categories.
ii. Uncertainties in Dispersion Modeling
While the analysis employed the EPA's recommended regulatory
dispersion model, AERMOD, we recognize that there is uncertainty in
ambient concentration estimates associated with any model, including
AERMOD. In circumstances where we had to choose between various model
options, where possible, model options (e.g., rural/urban, plume
depletion, chemistry) were selected to provide an overestimate of
ambient air concentrations of the HAP rather than underestimates.
However, because of practicality and data limitation reasons, some
factors (e.g., meteorology, building downwash) have the potential in
some situations to overestimate or underestimate ambient impacts. For
example, meteorological data were taken from a single year (1991) and
facility locations can be a significant distance from the site where
these data were taken. Despite these uncertainties, we believe that at
off-site locations and census block centroids, the approach considered
in the dispersion modeling analysis should generally yield
overestimates of ambient HAP concentrations.
iii. Uncertainties in Inhalation Exposure
The effects of human mobility on exposures were not included in the
assessment. Specifically, short-term mobility and long-term mobility
between census blocks in the modeling domain were not considered.\31\
The assumption of not considering short or long-term population
mobility does not bias the estimate of the theoretical MIR, nor does it
affect the estimate of cancer incidence since the total population
number remains the same. It does, however, affect the shape of the
distribution of individual risks across the affected population,
shifting it toward higher estimated individual risks at the upper end
and reducing the number of people estimated to be at lower risks,
thereby increasing the estimated number of people at specific risk
levels.
---------------------------------------------------------------------------
\31\ Short-term mobility is movement from one micro-environment
to another over the course of hours or days. Long-term mobility is
movement from one residence to another over the course of a
lifetime.
---------------------------------------------------------------------------
In addition, the assessment predicted the chronic exposures at the
centroid of each populated census block as surrogates for the exposure
concentrations for all people living in that block. Using the census
block centroid to predict chronic exposures tends to over-predict
exposures for people in the census block who live further from the
facility, and under-predict exposures for people in the census block
who live closer to the facility. Thus, using the census block centroid
to predict chronic exposures may lead to a potential understatement or
overstatement of the true maximum impact, but is an unbiased estimate
of average risk and incidence.
The assessments evaluate the cancer inhalation risks associated
with continuous pollutant exposures over a 70-year period, which is the
assumed lifetime of an individual. In reality, both the length of time
that modeled emissions sources at facilities actually operate (i.e.,
more or less than 70 years), and the domestic growth or decline of the
modeled industry (i.e., the increase
[[Page 52776]]
or decrease in the number or size of United States facilities), will
influence the risks posed by a given source category. Depending on the
characteristics of the industry, these factors will, in most cases,
result in an overestimate both in individual risk levels and in the
total estimated number of cancer cases. However, in rare cases, where a
facility maintains or increases its emission levels beyond 70 years,
residents live beyond 70 years at the same location, and the residents
spend most of their days at that location, then the risks could
potentially be underestimated. Annual cancer incidence estimates from
exposures to emissions from these sources would not be affected by
uncertainty in the length of time emissions sources operate.
The exposure estimates used in these analyses assume chronic
exposures to ambient levels of pollutants. Because most people spend
the majority of their time indoors, actual exposures may not be as
high, depending on the characteristics of the pollutants modeled. For
many of the HAP, indoor levels are roughly equivalent to ambient
levels, but for very reactive pollutants or larger particles, these
levels are typically lower. This factor has the potential to result in
an overstatement of 25 to 30 percent of exposures.\32\
---------------------------------------------------------------------------
\32\ U.S. EPA. National-Scale Air Toxics Assessment for 1996.
(EPA 453/R-01-003; January 2001; page 85.)
---------------------------------------------------------------------------
In addition to the uncertainties highlighted above, there are
several factors specific to the acute exposure assessment that should
be highlighted. The accuracy of an acute inhalation exposure assessment
depends on the simultaneous occurrence of independent factors that may
vary greatly, such as hourly emissions rates, meteorology, and human
activity patterns. In this assessment, we assume that individuals
remain for 1 hour at the point of maximum ambient concentration as
determined by the co-occurrence of peak emissions and worst-case
meteorological conditions. These assumptions would tend to overestimate
actual exposures since it is unlikely that a person would be located at
the point of maximum exposure during the time of worst-case impact.
iv. Uncertainties in Dose-Response Relationships
There are uncertainties inherent in the development of the dose-
response values used in our risk assessments for cancer effects from
chronic exposures and noncancer effects from both chronic and acute
exposures. Some uncertainties may be considered quantitatively, and
others generally are expressed in qualitative terms. We note as a
preface to this discussion a point on dose-response uncertainty that is
brought out in the EPA 2005 Cancer Guidelines; namely, that ``the
primary goal of the EPA actions is protection of human health;
accordingly, as an Agency policy, risk assessment procedures, including
default options that are used in the absence of scientific data to the
contrary, should be health protective.'' (EPA 2005 Cancer Guidelines,
pages 1-7.) This is the approach followed here as summarized in the
next several paragraphs. A complete detailed discussion of
uncertainties and variability in dose-response relationships is given
in the residual risk documentation, which is available in the docket
for this action.
Cancer URE values used in our risk assessments are those that have
been developed to generally provide an upper bound estimate of risk.
That is, they represent a ``plausible upper limit to the true value of
a quantity'' (although this is usually not a true statistical
confidence limit).\33\ In some circumstances, the true risk could be as
low as zero; however, in other circumstances, the risk could also be
greater.\34\ When developing an upper bound estimate of risk and to
provide risk values that do not underestimate risk, health-protective
default approaches are generally used. To err on the side of ensuring
adequate health-protection, the EPA typically uses the upper bound
estimates rather than lower bound or central tendency estimates in our
risk assessments, an approach that may have limitations for other uses
(e.g., priority-setting or expected benefits analysis).
---------------------------------------------------------------------------
\33\ IRIS glossary (http://www.epa.gov/NCEA/iris/help_gloss.htm).
\34\ An exception to this is the URE for benzene, which is
considered to cover a range of values, each end of which is
considered to be equally plausible and which is based on maximum
likelihood estimates.
---------------------------------------------------------------------------
Chronic noncancer reference (RfC and reference dose (RfD)) values
represent chronic exposure levels that are intended to be health-
protective levels. Specifically, these values provide an estimate (with
uncertainty spanning perhaps an order of magnitude) of daily oral
exposure (RfD) or of a continuous inhalation exposure (RfC) to the
human population (including sensitive subgroups) that is likely to be
without an appreciable risk of deleterious effects during a lifetime.
To derive values that are intended to be ``without appreciable risk,''
the methodology relies upon an uncertainty factor (UF) approach (U.S.
EPA, 1993, 1994) which includes consideration of both uncertainty and
variability. When there are gaps in the available information, UF are
applied to derive reference values that are intended to protect against
appreciable risk of deleterious effects. The UF are commonly default
values,\35\ e.g., factors of 10 or 3, used in the absence of compound-
specific data; where data are available, UF may also be developed using
compound-specific information. When data are limited, more assumptions
are needed and more UF are used. Thus, there may be a greater tendency
to overestimate risk in the sense that further study might support
development of reference values that are higher (i.e., less potent)
because fewer default assumptions are needed. However, for some
pollutants, it is possible that risks may be underestimated. While
collectively termed ``uncertainty factor,'' these factors account for a
number of different quantitative considerations when using observed
animal (usually rodent) or human toxicity data in the development of
the RfC. The UF are intended to account for: (1) Variation in
susceptibility among the members of the human population (i.e., inter-
individual variability); (2) uncertainty in extrapolating from
experimental animal data to humans (i.e., interspecies differences);
(3) uncertainty in extrapolating from data obtained in a study with
less-than-lifetime exposure (i.e., extrapolating from sub-chronic to
chronic exposure); (4) uncertainty in extrapolating the observed data
to obtain an estimate of the exposure associated with no adverse
effects; and (5) uncertainty when the database is incomplete or there
are problems with the applicability of available studies. Many of the
UF used to account for variability and uncertainty in the development
of acute reference values
[[Page 52777]]
are quite similar to those developed for chronic durations, but they
more often use individual UF values that may be less than 10. UF are
applied based on chemical-specific or health effect-specific
information (e.g., simple irritation effects do not vary appreciably
between human individuals, hence a value of 3 is typically used), or
based on the purpose for the reference value (see the following
paragraph). The UF applied in acute reference value derivation include:
(1) Heterogeneity among humans; (2) uncertainty in extrapolating from
animals to humans; (3) uncertainty in lowest observed adverse effect
(exposure) level to no observed adverse effect (exposure) level
adjustments; and (4) uncertainty in accounting for an incomplete
database on toxic effects of potential concern. Additional adjustments
are often applied to account for uncertainty in extrapolation from
observations at one exposure duration (e.g., 4 hours) to derive an
acute reference value at another exposure duration (e.g., 1 hour).
---------------------------------------------------------------------------
\35\ According to the NRC report, Science and Judgment in Risk
Assessment (NRC, 1994) ``[Default] options are generic approaches,
based on general scientific knowledge and policy judgment, that are
applied to various elements of the risk assessment process when the
correct scientific model is unknown or uncertain.'' The 1983 NRC
report, Risk Assessment in the Federal Government: Managing the
Process, defined default option as ``the option chosen on the basis
of risk assessment policy that appears to be the best choice in the
absence of data to the contrary'' (NRC, 1983a, p. 63). Therefore,
default options are not rules that bind the Agency; rather, the
Agency may depart from them in evaluating the risks posed by a
specific substance when it believes this to be appropriate. In
keeping with EPA's goal of protecting public health and the
environment, default assumptions are used to ensure that risk to
chemicals is not underestimated (although defaults are not intended
to overtly overestimate risk). See EPA, 2004, An Examination of EPA
Risk Assessment Principles and Practices, EPA/100/B-04/001 available
at: http://www.epa.gov/osa/pdfs/ratf-final.pdf.
---------------------------------------------------------------------------
Not all acute reference values are developed for the same purpose
and care must be taken when interpreting the results of an acute
assessment of human health effects relative to the reference value or
values being exceeded. Where relevant to the estimated exposures, the
lack of short-term dose-response values at different levels of severity
should be factored into the risk characterization as potential
uncertainties.
Although every effort is made to identify peer-reviewed reference
values for cancer and noncancer effects for all pollutants emitted by
the sources included in this assessment, some HAP continue to have no
reference values for cancer or chronic noncancer or acute effects.
Since exposures to these pollutants cannot be included in a
quantitative risk estimate, an understatement of risk for these
pollutants at environmental exposure levels is possible. For a group of
compounds that are either unspeciated or do not have reference values
for every individual compound (e.g., glycol ethers), we conservatively
use the most protective reference value to estimate risk from
individual compounds in the group of compounds.
Additionally, chronic reference values for several of the compounds
included in this assessment are currently under the EPA IRIS review and
revised assessments may determine that these pollutants are more or
less potent than the current value. We may re-evaluate residual risks
for the final rulemaking if these reviews are completed prior to our
taking final action for these source categories and a dose-response
metric changes enough to indicate that the risk assessment supporting
this notice may significantly understate human health risk.
v. Uncertainties in the Multi-Pathway and Environmental Effects
Assessment
We generally assume that when exposure levels are not anticipated
to adversely affect human health, they also are not anticipated to
adversely affect the environment. For each source category, we
generally rely on the site-specific levels of PB-HAP emissions to
determine whether a full assessment of the multi-pathway and
environmental effects is necessary. As discussed above, we conclude
that the potential for these types of impacts is low for these source
categories.
vi. Uncertainties in the Facility-Wide Risk Assessment
Given that the same general analytical approach and the same models
were used to generate facility-wide risk results as were used to
generate the source category risk results, the same types of
uncertainties discussed above for our source category risk assessments
apply to the facility-wide risk assessments. Additionally, the degree
of uncertainty associated with facility-wide emissions and risks is
likely greater because we generally have not conducted a thorough
engineering review of emissions data for source categories not
currently undergoing an RTR review.
vii. Uncertainties in the Demographic Analysis
Our analysis of the distribution of risks across various
demographic groups is subject to the typical uncertainties associated
with census data (e.g., errors in filling out and transcribing census
forms), as well as the additional uncertainties associated with the
extrapolation of census-block group data (e.g., income level and
education level) down to the census block level.
2. What are the results and proposed decisions from the risk review for
the Oil and Natural Gas Production source category?
a. Results of the Risk Assessments and Analyses
We conducted an inhalation risk assessment for the Oil and Natural
Gas Production source category. We also conducted an assessment of
facility-wide risk. Details of the risk assessments and analyses can be
found in the residual risk documentation, which is available in the
docket for this action. For informational purposes and to examine the
potential for any EJ issues that might be associated with each source
category, we performed a demographic analysis of population risks.
i. Inhalation Risk Assessment Results
Table 2 provides an overall summary of the results of the
inhalation risk assessment.
Table 2--Oil and Natural Gas Production Inhalation Risk Assessment Results
--------------------------------------------------------------------------------------------------------------------------------------------------------
Maximum individual cancer risk (in 1 Maximum chronic noncancer TOSHI \4\
million) \2\ Estimated Estimated annual -------------------------------------- Maximum off-site
Number of --------------------------------------- population at cancer incidence acute noncancer
facilities \1\ Actual emissions Allowable risk >= 1-in-1 (cases per year) Actual emissions Allowable HQ \5\
level emissions level million level emissions level
--------------------------------------------------------------------------------------------------------------------------------------------------------
990 40 100-400 \3\ 160,000 \3\ 0.007-0.02 \3\ 0.1 0.7 HQREL = 9
(benzene)
HQAEGL 1 = 0.07
(benzene)
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Number of facilities evaluated in the risk analysis.
\2\ Estimated maximum individual excess lifetime cancer risk.
\3\ The EPA IRIS assessment for benzene provides a range of equally-plausible URE (2.2E-06 to 7.8E-06 per ug/m3), giving rise to ranges for the
estimates of cancer MIR and cancer incidence. Estimated population values are not scalable with benzene URE range, but would be lower using the lower
end of the URE range.
\4\ Maximum TOSHI. The target organ with the highest TOSHI for the Oil and Natural Gas Production source category is the respiratory system.
\5\ The maximum estimated acute exposure concentration was divided by available short-term dose-response values to develop an array of HQ values.
[[Page 52778]]
As shown in Table 2, the results of the inhalation risk assessment
performed using actual emissions data indicate the maximum lifetime
individual cancer risk could be as high as 40-in-1 million, with POM
driving the highest risk, and benzene driving risks overall. The total
estimated cancer incidence from this source category is 0.02 excess
cancer cases per year (0.007 excess cancer cases per year based on the
lower end of the benzene URE range), or one case in every 50 years.
Approximately 160,000 people are estimated to have cancer risks at or
above 1-in-1 million as a result of the emissions from 89 facilities
(use of the lower end of the benzene URE range would further reduce
this population estimate). The maximum chronic non-cancer TOSHI value
for the source category could be up to 0.1 from emissions of
naphthalene, indicating no significant potential for chronic noncancer
impacts.
As explained above, our analysis of potential differences between
actual emission levels and emissions allowable under the oil and
natural gas production MACT standard indicate that MACT-allowable
emission levels may be up to 50 times greater than actual emission
levels. Considering this difference, the risk results from the
inhalation risk assessment indicate the maximum lifetime individual
cancer risk could be as high as 400-in-1 million (100-in-1 million
based on the lower end of the benzene URE range) and the maximum
chronic noncancer TOSHI value could be as high as 0.7 at the MACT-
allowable emissions level.
ii. Facility-Wide Risk Assessment Results
A facility-wide risk analysis was also conducted based on actual
emissions levels. Table 3 displays the results of the facility-wide
risk assessment. For detailed facility-specific results, see Table 2 of
Appendix 6 of the risk document in the docket for this rulemaking.
Table 3--Oil and Natural Gas Production Facility-Wide Risk Assessment
Results
------------------------------------------------------------------------
------------------------------------------------------------------------
Number of facilities analyzed.............................. 990
Cancer Risk:
Estimated maximum facility-wide individual cancer risk 100
(in 1 million)........................................
Number of facilities with estimated facility-wide 1
individual cancer risk of 100-in-1 million or more....
Number of facilities at which the Oil and Natural Gas 0
Production source category contributes 50 percent or
more to the facility-wide individual cancer risks of
100-in-1 million or more..............................
Number of facilities with facility-wide individual 140
cancer risk of 1-in-1 million or more.................
Number of facilities at which the Oil and Natural Gas 85
Production source category contributes 50 percent or
more to the facility-wide individual cancer risk of 1-
in-1 million or more..................................
Chronic Noncancer Risk:
Maximum facility-wide chronic noncancer TOSHI.......... 9
Number of facilities with facility-wide maximum 10
noncancer TOSHI greater than 1........................
Number of facilities at which the Oil and Natural Gas 0
Production source category contributes 50 percent or
more to the facility-wide maximum noncancer TOSHI of 1
or more...............................................
------------------------------------------------------------------------
The facility-wide MIR from all HAP emissions at a facility that
contains sources subject to the oil and natural gas production MACT
standards is estimated to be 100-in-1 million, based on actual
emissions. Of the 990 facilities included in this analysis, only one
has a facility-wide MIR of 100-in-1 million. At this facility, oil and
natural gas production accounts for less than 2 percent of the total
facility-wide risk. Nickel emissions from oil-fired boilers and
formaldehyde emissions from reciprocating internal combustion engines
(RICE) contribute essentially all the facility-wide risks at this
facility, with over 80 percent of the risk attributed to the nickel
emissions.\36\ There are 140 facilities with facility-wide MIR of 1-in-
1 million or greater. Of these facilities, 85 have oil and natural gas
production operations that contribute greater than 50 percent to the
facility-wide risks. As discussed above, we are proposing MACT
standards for BTEX emissions from small glycol dehydrators in this
action. These standards would reduce the risk from benzene emissions at
facilities with oil and gas production. Formaldehyde emissions will be
assessed under future RTR for RICE.
---------------------------------------------------------------------------
\36\ We note that there is an ongoing IRIS reassessment for
formaldehyde, and that future RTR risk assessments will use the
cancer potency for formaldehyde that results from that reassessment.
As a result, the current results may not match those of future
assessments.
---------------------------------------------------------------------------
The facility-wide maximum individual chronic noncancer TOSHI is
estimated to be 9 based on actual emissions. Of the 990 facilities
included in this analysis, 10 have facility-wide maximum chronic
noncancer TOSHI values greater than 1. Of these facilities, none had
oil and natural gas production operations that contributed greater than
50 percent to these facility-wide risks. The chronic noncancer risks at
these 10 facilities are primarily driven by acrolein emissions from
RICE.
iii. Demographic Risk Analysis Results
The results of the demographic analyses performed to investigate
the distribution of cancer risks at or above 1-in-1 million among the
surrounding population are summarized in Table 4 below. These results,
for various demographic groups, are based on actual emissions levels
for the population living within 50 km of the facilities.
Table 4--Oil and Natural Gas Production Demographic Risk Analysis Results
----------------------------------------------------------------------------------------------------------------
Population with cancer risk at or
above 1-in-1 million due to
Nationwide -------------------------------------
Source category Facility-wide HAP
HAP emissions emissions
----------------------------------------------------------------------------------------------------------------
Total Population....................................... 285,000,000 160,000 597,000
[[Page 52779]]
Race by Percent
----------------------------------------------------------------------------------------------------------------
White.................................................. 75 62 61
All Other Races........................................ 25 38 39
----------------------------------------------------------------------------------------------------------------
Race by Percent
----------------------------------------------------------------------------------------------------------------
White.................................................. 75 62 61
African American....................................... 12 12 8
Native American........................................ 0.9 0.7 1.3
Other and Multiracial.................................. 12 25 30
----------------------------------------------------------------------------------------------------------------
Ethnicity by Percent
----------------------------------------------------------------------------------------------------------------
Hispanic............................................... 14 22 34
Non-Hispanic........................................... 86 78 66
----------------------------------------------------------------------------------------------------------------
Income by Percent
----------------------------------------------------------------------------------------------------------------
Below Poverty Level.................................... 13 14 19
Above Poverty Level.................................... 87 86 81
----------------------------------------------------------------------------------------------------------------
Education by Percent
----------------------------------------------------------------------------------------------------------------
Over 25 and without High School Diploma................ 13 10 16
Over 25 and with a High School Diploma................. 87 90 84
----------------------------------------------------------------------------------------------------------------
The results of the Oil and Natural Gas Production source category
demographic analysis indicate that there are approximately 160,000
people exposed to a cancer risk at or above 1-in-1 million due to
emissions from the source category, including an estimated 38 percent
that are classified as minority (listed as ``All Other Races'' in the
table above). Of the 160,000 people with estimated cancer risks at or
above 1-in-1 million from the source category, 25 percent are in the
``Other and Multiracial'' demographic group, 22 percent are in the
``Hispanic or Latino'' demographic group, and 14 percent are in the
``Below Poverty Level'' demographic group, results which are 13, 8 and
1 percentage points higher, respectively, than the respective
percentages for these demographic groups across the United States. The
percentages for the other demographic groups are lower than their
respective nationwide percentages. The table also shows that there are
approximately 597,000 people exposed to an estimated cancer risk at or
above 1-in-1 million due to facility-wide emissions, including 30
percent in the ``Other and Multiracial'' demographic group, 34 percent
in the ``Hispanic or Latino'' demographic group, 1.3 percent in the
``Native American'' demographic group and 16 percent in the ``Over 25
and without High School Diploma'' demographic group, results which are
18, 2, 0.4 and 3 percentage points higher than the percentages for
these demographic groups across the United States, respectively. The
percentages for the other demographic groups are lower than their
respective nationwide percentages.
b. What are the proposed risk decisions for the Oil and Natural Gas
Production source category?
i. Risk Acceptability
In the risk analysis we performed for this source category,
pursuant to CAA section 112(f)(2), we considered the available health
information--the MIR; the numbers of persons in various risk ranges;
cancer incidence; the maximum noncancer HI; the maximum acute noncancer
hazard; the extent of noncancer risks; the potential for adverse
environmental effects; and distribution of risks in the exposed
population; and risk estimation uncertainty (54 FR 38044, September 14,
1989).
For the Oil and Natural Gas Production source category, the risk
analysis we performed indicates that the cancer risks to the individual
most exposed could be as high as 40-in-1 million due to actual
emissions and as high as 400-in-1 million due to MACT-allowable
emissions (100-in-1 million, based on the lower end of the benzene URE
range). While the 40-in-1 million risk due to actual emissions is
considerably less than 100-in-1 million, which is the presumptive limit
of acceptability, the 400-in-1 million risk due to allowable emissions
is considerably higher and is considered unacceptable. We do note,
however, that the risk analysis shows low cancer incidence (1 case in
every 50 years), low potential for adverse environmental effects or
human health multi-pathway effects and that chronic noncancer health
impacts are unlikely.
We also conclude that acute noncancer health impacts are unlikely.
As discussed above, screening estimates of acute exposures and risks
were evaluated for each of the HAP at the point of highest off-site
exposure for each facility (i.e., not just the census block centroids)
assuming that a person is located at this spot at a time when both the
peak emission rate and worst-case dispersion conditions occur. Under
these worst-case conditions, we estimate benzene acute HQ values (based
on the REL) could be as high as 9. Although the REL (which indicates
the level below which adverse effects are not anticipated) is exceeded
in this case, we believe the potential for acute effects is low for
several reasons. First, the acute modeling scenario is worst-case
because of the confluence of peak emission rates and worst-case
dispersion conditions.
[[Page 52780]]
Second, the benzene REL is based on a 6-hour exposure duration because
a 1-hour exposure duration value was unavailable. An REL based on a 6-
hour exposure duration is generally lower than an REL based on a 1-hour
exposure duration and, consequently, easier to exceed. Also, although
there are exceedances of the REL, the highest estimated 1-hour exposure
is less than 10 percent of the AEGL-1 value, which is a level at which
effects could be experienced. Finally, the generally sparse populations
near these facilities make it less likely that a person would be near
the plant to be exposed. For example, in the two cases where the acute
HQ value is as high as 9, there are only 30 people associated with the
census blocks within 2 miles of the two facilities.
While our additional analysis of facility-wide risks showed that
there is one facility with maximum facility-wide cancer risk of 100-in-
1 million or greater and 10 facilities with a maximum chronic noncancer
TOSHI greater than 1, it also showed that oil and natural gas
production operations did not drive these risks.
In determining whether risk is acceptable, we considered the
available health information, as described above. In this case,
although a number of factors we considered indicate relatively low risk
concern, we are proposing to determine that the risks are unacceptable,
in large part, because the MIR is 400-in-1 million due to MACT-
allowable emissions, which greatly exceeds the ``presumptive limit on
maximum individual lifetime risk of approximately 1-in-10 thousand
[100-in-1 million] recognized in the Benzene NESHAP (54 FR 38045).''
The MIR, based on MACT-allowable emissions, is driven by the allowable
emissions of 0.9 Mg/yr benzene under the MACT as a compliance option.
We are, therefore, proposing to eliminate the alternative compliance
option of 0.9 Mg/yr benzene from the existing glycol dehydrator MACT
requirements. With this change, the source category MIR, based on MACT-
allowable emissions, would be reduced to 40-in-1 million, which we find
acceptable in light of all the other factors considered. Thus, we are
proposing that the risks from the Oil and Natural Gas Production source
category are acceptable, with the removal of the alternative compliance
option of 0.9 Mg/yr benzene limit from the current glycol dehydrator
MACT requirements.
Pursuant to CAA section 112(f)(4), we are proposing that this
change (i.e., removal of the 0.9 Mg/yr compliance alternative) apply 90
days after its effective date. We are requesting comment on whether or
not this is sufficient time for the large dehydrators that have been
relying on this compliance alternative to come into compliance with the
95-percent control requirement or if additional time is needed. See CAA
section 112(f)(4)(A).
We recognize that our proposal to remove the 0.9 Mg/yr compliance
alternative for the 95-percent control glycol dehydrator MACT standard
could have negative impacts on some sources that have come to rely on
the flexibility this alternative provides. We solicit comment on any
such impacts and whether such impacts warrant adding a different
compliance alternative that would result in less risk than the 0.9 Mg/
yr benzene limit compliance option. If a commenter suggests a different
compliance alternative, the commenter should explain, in detail, what
that alternative would be, how it would work and how it would reduce
risk.
ii. Ample Margin of Safety
We next considered whether this revised standard (existing MACT
plus removal of 0.9 Mg/yr benzene compliance option) provides an ample
margin of safety. In this analysis, we investigated available emissions
control options that might reduce the risk associated with emissions
from the source category and considered this information along with all
of the health risks and other health information considered in the risk
acceptability determination.
For glycol dehydrators, we considered the addition of a second
control device in the same manner that was discussed in the floor
evaluation in section VII.B.1 above. The cost effectiveness associated
with that option would be $167,200/Mg, which we believe is too high to
require additional controls on glycol dehydrators.
Similarly, we considered the addition of a second control device to
the required MACT floor control device (cost effectiveness of $18,300/
Mg). Similar to our discussion of beyond-the-MACT-floor controls for
glycol dehydrators in section VII.B.1 of this preamble, the incremental
cost to add a second control device for storage vessels would be
approximately 20 times higher than the MACT floor cost effectiveness,
or $366,000/Mg. We do not believe this cost effectiveness is
reasonable.
For leak detection, we considered implementation of LDAR programs
that are more stringent than the current standards. An assessment
performed for various LDAR options under the NSPS in section VI.B.4.b
of this preamble yielded the lowest cost effectiveness of $5,170/Mg
($4,700/ton) for control of VOC for the options evaluated. A LDAR
program to control HAP would involve similar costs for equipment,
labor, etc., to those considered in the NSPS assessment, but since
there is approximately 20 times less HAP than VOC present in material
handled in regulated equipment, the cost effectiveness to control HAP
would be approximately 20 times greater (i.e., $100,000/Mg) for HAP,
which we believe is not reasonable.
In accordance with the approach established in the Benzene NESHAP,
the EPA weighed all health risk measures and information considered in
the risk acceptability determination, along with the costs and economic
impacts of emissions controls, technological feasibility, uncertainties
and other relevant factors in making our ample margin of safety
determination. Considering the health risk information and the high
cost effectiveness of the options identified, we propose that the
existing MACT standards, with the removal of the 1 tpy benzene limit
compliance option from the glycol dehydrator standards, provide an
ample margin of safety to protect public health.
While we are proposing that the oil and natural gas production MACT
standards (with the removal of the alternative compliance option of 1
tpy benzene limit) provide an ample margin of safety to protect public
health, we are concerned about the estimated facility-wide risks
identified through these screening analyses. As described previously,
the highest estimated facility-wide cancer risks are mostly due to
emissions from oil fired boilers and RICE. Both of these sources are
regulated under other source categories and we anticipate that emission
reductions from those sources will occur as standards for those source
categories are implemented.
3. What are the results and proposed decisions from the risk review for
the Natural Gas Transmission and Storage source category?
a. Results of the Risk Assessments and Analyses
We conducted an inhalation risk assessment for the Natural Gas
Transmission and Storage source category. We also conducted an
assessment of facility-wide risk and performed a demographic analysis
of population risks. Details of the risk assessments and analyses can
be found in the residual risk documentation, which is available in the
docket for this action.
[[Page 52781]]
i. Inhalation Risk Assessment Results
Table 5 provides an overall summary of the results of the
inhalation risk assessment. For informational purposes and to examine
the potential for any EJ issues that might be associated with each
source category, we performed a demographic analysis of population
risks.
Table 5--Natural Gas Transmission and Storage Inhalation Risk Assessment Results
--------------------------------------------------------------------------------------------------------------------------------------------------------
Maximum individual cancer risk (in 1 Maximum chronic noncancer TOSHI \4\
million) \2\ Estimated Estimated annual -------------------------------------- Maximum off-site
Number of --------------------------------------- population at cancer incidence acute noncancer
Facilities \1\ Actual emissions Allowable risk >= 1-in-1 (cases per year) Actual emissions Allowable HQ \5\
level emissions level million level emissions level
--------------------------------------------------------------------------------------------------------------------------------------------------------
321 \3\ 30-90 \3\ 30-90 \3\ 2,500 \3\ 0.0003-0.001 0.4 0.8 HQREL = 5
(benzene)
HQAEGL 1 = 0.2
(chlorobenzene)
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Number of facilities evaluated in the risk analysis.
\2\ Estimated maximum individual excess lifetime cancer risk.
\3\ The EPA IRIS assessment for benzene provides a range of equally-plausible URE (2.2E-06 to 7.8E-06 per ug/m\3\), giving rise to ranges for the
estimates of cancer MIR and cancer incidence. Estimated population values are not scalable with benzene URE range, but would be lower using the lower
end of the URE range.
\4\ Maximum TOSHI. The target organ with the highest TOSHI for the Natural Gas Transmission and Storage source category is the immune system.
\5\ The maximum estimated acute exposure concentration was divided by available short-term dose-response values to develop an array of HQ values.
As shown in Table 5 above, the results of the inhalation risk
assessment performed using actual emissions data indicate the maximum
lifetime individual cancer risk could be as high as 90-in-1 million,
(30-in-1 million based on the lower end of the benzene URE range), with
benzene as the major contributor to the risk. The total estimated
cancer incidence from the source category is 0.001 excess cancer cases
per year (0.0003 excess cancer cases per year based on the lower end of
the benzene URE range), or one case in every polycyclic organic matter
1,000 years. Approximately 2,500 people are estimated to have cancer
risks at or above 1-in-1 million as a result of the emissions from 15
facilities (use of the lower end of the benzene URE range would further
reduce this population estimate). The maximum chronic noncancer TOSHI
value for the source category could be up to 0.4 from emissions of
benzene, indicating no significant potential for chronic noncancer
impacts.
As explained above in section VII.C.1.b, our analysis of potential
differences between actual emission levels and emissions allowable
under the natural gas transmission and storage MACT standard indicate
that MACT-allowable emission levels may be up to 50 times greater than
actual emission levels at some sources. However, because some sources
are emitting at the level allowed under the current NESHAP, the risk
results from the inhalation risk assessment indicate the maximum
lifetime individual cancer risk would still be 90-in-1 million (30-in-1
million based on the lower end of the benzene URE range), based on both
actual and allowable emission levels, and the maximum chronic noncancer
TOSHI value could be as high as 0.8 at the MACT-allowable emissions
level.
ii. Facility-Wide Risk Assessment Results
A facility-wide risk analysis was also conducted based on actual
emissions levels. Table 6 below displays the results of the facility-
wide risk assessment. For detailed facility-specific results, see Table
2 of Appendix 6 of the risk document in the docket for this rulemaking.
Table 6--Natural Gas Transmission and Storage Facility-Wide Risk
Assessment Results
------------------------------------------------------------------------
------------------------------------------------------------------------
Number of Facilities Analyzed.............................. 321
Number of facilities with estimated facility-wide 3
individual cancer risk of 100-in-1 million or more....
Number of facilities at which the Natural Gas 1
Transmission and Storage source category contributes
50 percent or more to the facility-wide individual
cancer risks of 100-in-1 million or more..............
Number of facilities with facility-wide individual 74
cancer risk of 1-in-1 million or more.................
Number of facilities at which the Natural Gas 10
Transmission and Storage source category contributes
50 percent or more to the facility-wide individual
cancer risk of 1-in-1 million or more.................
Chronic Noncancer Risk:
Maximum facility-wide chronic noncancer TOSHI.......... 80
Number of facilities with facility-wide maximum 30
noncancer TOSHI greater than 1........................
Number of facilities at which the Natural Gas 0
Transmission and Storage source category contributes
50 percent or more to the facility-wide maximum
noncancer TOSHI of 1 or more..........................
------------------------------------------------------------------------
\1\ We note that the MIR would be 100-in-1 million if the CIIT URE for
formaldehyde were used instead of the IRIS URE.
The facility-wide MIR from all HAP emissions at any facility that
contains sources subject to the natural gas transmission and storage
MACT standards is estimated to be 200-in-1 million, based on actual
emissions. Of the 321 facilities included in this analysis, three have
facility-wide MIR of 100-in-1 million or greater. The facility-wide MIR
is 200-in-1 million at two of these facilities, driven by formaldehyde
[[Page 52782]]
from RICE.\37\ Another facility has a facility-wide risk of 100-in-1
million, with 90 percent of the risk attributed to natural gas
transmission and storage. There are 74 facilities with facility-wide
MIR of 1-in-1 million or greater. Of these facilities, 10 have natural
gas transmission and storage operations that contribute greater than 50
percent to the facility-wide risks. As discussed above, we are
proposing MACT standards for benzene emissions from small glycol
dehydrators in this action. These standards would reduce the risk from
benzene emissions at facilities with natural gas transmission and
storage operations. The facility-wide cancer risks at the facilities
with risks of 1-in-1 million or more are primarily driven by
formaldehyde emissions from RICE, which will be assessed in a future
RTR for that category.
---------------------------------------------------------------------------
\37\ We note that there is an ongoing IRIS reassessment for
formaldehyde, and that future RTR risk assessments will use the
cancer potency for formaldehyde that results from that reassessment.
As a result, the current results may not match those of future
assessments.
---------------------------------------------------------------------------
The facility-wide maximum individual chronic noncancer TOSHI is
estimated to be 80, based on actual emissions. Of the 321 facilities
included in this analysis, 30 have facility-wide maximum chronic
noncancer TOSHI values greater than 1. Of these facilities, none had
natural gas transmission and storage operations that contributed
greater than 50 percent to these facility-wide risks. The chronic
noncancer risks at these facilities are primarily driven by acrolein
emissions from RICE.
iii. Demographic Risk Analysis Results
The results of the demographic analyses performed to investigate
the distribution of cancer risks at or above 1-in-1 million among the
surrounding population are summarized in Table 7 below. These results,
for various demographic groups, are based on actual emissions levels
for the population living within 50 km of the facilities.
Table 7--Natural Gas Transmission and Storage Demographic Risk Analysis Results
----------------------------------------------------------------------------------------------------------------
Population with cancer risk at or
above 1-in-1 million due to . . .
Nationwide -------------------------------------
Source category Facility-wide HAP
HAP emissions emissions
----------------------------------------------------------------------------------------------------------------
Total Population....................................... 285,000,000 2,500 99,000
----------------------------------------------------------------------------------------------------------------
Race by Percent
----------------------------------------------------------------------------------------------------------------
White.................................................. 75 92 58
All Other Races........................................ 25 8 42
----------------------------------------------------------------------------------------------------------------
Race by Percent
----------------------------------------------------------------------------------------------------------------
White.................................................. 75 92 58
African American....................................... 12 6 40
Native American........................................ 0.9 0.1 0.2
Other and Multiracial.................................. 12 1 2
----------------------------------------------------------------------------------------------------------------
Ethnicity by Percent
----------------------------------------------------------------------------------------------------------------
Hispanic............................................... 14 1 2
Non-Hispanic........................................... 86 99 98
----------------------------------------------------------------------------------------------------------------
Income by Percent
----------------------------------------------------------------------------------------------------------------
Below Poverty Level.................................... 13 17 20
Above poverty level.................................... 87 83 80
----------------------------------------------------------------------------------------------------------------
Education by Percent
----------------------------------------------------------------------------------------------------------------
Over 25 and without High School Diploma................ 13 20 15
Over 25 and with a High School Diploma................. 87 80 85
----------------------------------------------------------------------------------------------------------------
The results of the Natural Gas Transmission and Storage source
category demographic analysis indicate that there are approximately
2,500 people exposed to a cancer risk at or above 1-in-1 million due to
emissions from the source category, including an estimated 8 percent
that are classified as minority (listed as ``All Other Races'' in Table
7 above). Of the 2,500 people with estimated cancer risks at or above
1-in-1 million from the source category, 17 percent are in the ``Below
Poverty Level'' demographic group, and 20 percent are in the ``Over 25
and without High School Diploma'' demographic group, results which are
4 and 7 percentage points higher, respectively, than the percentages
for these demographic groups across the United States. The percentages
for the other demographic groups are lower than their respective
nationwide percentages. The table also shows that there are
approximately 99,000 people exposed to an estimated cancer risk at or
above 1-in-1 million due to facility-wide emissions, including an
estimated 42 percent that are classified as minority (``All Other
Races'' in Table 7 above). Of the 99,000 people with estimated cancer
risk at or above 1-in-1 million from facility-wide emissions, 40
percent are in the ``African American'' demographic group, 20 percent
are in the ``Below Poverty Level'' demographic group, and 15 percent
are in the ``Over 25 and without High School Diploma'' demographic
group, results which are 28, 7 and 2 percentage points higher,
respectively, than the percentages for these demographic groups across
the United States. The percentages for the other demographic groups are
equal to
[[Page 52783]]
or lower than their respective nationwide percentages.
b. What are the proposed risk decisions for the Natural Gas
Transmission and Storage source category?
i. Risk Acceptability
In the risk analysis we performed for this source category,
pursuant to CAA section 112(f)(2), we considered the available health
information--the MIR; the numbers of persons in various risk ranges;
cancer incidence; the maximum noncancer HI; the maximum acute noncancer
hazard; the extent of noncancer risks; the potential for adverse
environmental effects; distribution of risks in the exposed population;
and risk estimation uncertainty (54 FR 38044, September 14, 1989).
For the Natural Gas Transmission and Storage source category, the
risk analysis we performed indicates that the cancer risks to the
individual most exposed could be as high as 90-in-1 million due to
actual and allowable emissions (30-in-1 million, based on the lower end
of the benzene URE range). These risks are near 100-in-1 million, which
is the presumptive limit of acceptability. On the other hand, the risk
analysis shows low cancer incidence (1 case in every 1,000 years), low
potential for adverse environmental effects or human health multi-
pathway effects and that chronic and acute noncancer health impacts are
unlikely. We conclude that acute noncancer health impacts are unlikely
for reasons similar to those described in section VII.C.2.b.i of this
preamble.
Our additional analysis of facility-wide risks showed that, among
three facilities with maximum facility-wide cancer risk of 100-in-1
million or greater, one facility has a facility-wide cancer risk of
100-in-1 million, with 90 percent of the risk attributed to natural gas
and transmission and storage. There are 30 facilities with a maximum
chronic noncancer TOSHI greater than 1, but natural gas transmission
and storage operations did not drive this risk.
In determining whether risk is acceptable, we considered the
available health information, as described above. In this case, because
the MIR is approaching, but still less than 100-in-1 million risk, and
because a number of other factors indicate relatively low risk concern
(e.g., low cancer incidence, low potential for adverse environmental
effects or human health multi-pathway effects, chronic and acute
noncancer health impacts unlikely), we are proposing to determine that
the risks are acceptable.
ii. Ample Margin of Safety
We next considered whether the existing MACT standard provides an
ample margin of safety. In this analysis, we investigated available
emissions control options that might reduce the risk associated with
emissions from the source category and considered this information,
along with all of the health risks and other health information
considered in the risk acceptability determination. The estimated MIR
of 90-in-1 million discussed above is driven by the 0.9 Mg/year benzene
limit compliance alternative for the glycol dehydrator MACT standard in
the current NESHAP. Removal of this compliance alternative would lower
the MIR for the source category to 20-in-1 million. We, therefore,
considered removing this compliance alternative as an option for
reducing risk and assessed the cost of such alternative. Without the
compliance alternative, affected glycol dehydrators (i.e., those units
with annual average benzene emissions of 0.9 Mg/yr or greater and an
annual average natural gas throughput of 283,000 scmd or greater) must
demonstrate compliance with the 95-percent control requirement, which
we believe can be shown with their existing control devices in most
cases, although, in some instances, installation of a different or an
additional control may be necessary.
In section VII.B.1 above, we discuss the costs for requiring
controls on currently unregulated ``small glycol dehydrators,'' which
are similar, in operation and type of emission controls, to the
dehydrators subject to the current MACT (``large dehydrators''). The
HAP cost effectiveness determined for small dehydrators at the floor
level of control was $1,650/Mg. Although control methodologies are
similar for large and small dehydrators, we expect that the costs for
controls on large units could be as much as twice as high as for small
units because of the large gas flow being processed. However, we also
expect that the amount of HAP emission reduction for the large
dehydrators, in general, to be as much as, or more than, the amount
achieved by small dehydrators. In light of the above, we do not expect
the cost effectiveness of the control device needed to meet the 95-
percent control requirement for large dehydrators to exceed $3,300/Mg
(i.e., twice the cost effectiveness for small dehydrators), which we
consider to be reasonable.
In accordance with the approach established in the Benzene NESHAP,
the EPA weighed all health risk measures and information considered in
the risk acceptability determination, along with the costs and economic
impacts of emissions controls, technological feasibility, uncertainties
and other relevant factors in making our ample margin of safety
determination. Considering the health risk information and the
reasonable cost effectiveness of the option identified, we propose that
the existing MACT standards, with the removal of the 0.9 Mg benzene
limit compliance option from the glycol dehydrator standards, provide
an ample margin of safety to protect public health.
Pursuant to CAA section 112(f)(4), we are proposing that this
change (i.e., removal of the 0.9 Mg/yr compliance alternative) apply 90
days after its effective date. We are requesting comment on whether or
not there is sufficient time for the large dehydrators that have been
relying on this compliance alternative to come into compliance with the
95-percent control requirement or if additional time is needed. See CAA
section 112(f)(4)(A).
We recognize that our proposal to remove the one-ton compliance
alternative for the 95-percent control glycol dehydrator MACT standard
could have negative impacts on some sources that have come to rely on
the flexibility this alternative provides. We solicit comment on any
such impacts and whether such impacts warrant adding a different
compliance alternative that would result in less risk than the 0.9 Mg/
yr benzene limit compliance option. If a commenter suggests a different
compliance alternative, the commenter should explain, in detail, what
that alternative would be, how it would work, and how it would reduce
risk.
As described above, we are proposing that the natural gas
transmission and storage MACT standards (with the removal of the 0.9
Mg/yr benzene limit compliance option) provide an ample margin of
safety to protect public health. We recognize that one facility has a
facility-wide cancer risk of 100-in-1 million, with 90 percent of the
risk attributed to natural gas transmission and storage. This risk is
driven by benzene emissions from glycol dehydrators and is being
addressed by our proposed revision to the Natural Gas Transmission and
Storage NESHAP (removal of the 0.9 Mg/yr benzene limit compliance
option). As previously mentioned, two facilities have facility-wide MIR
of 200-in-1 million, driven by formaldehyde from RICE. Emissions from
RICE are regulated under another source category and will be assessed
under a future RTR for that category.
[[Page 52784]]
D. How did we perform the technology review and what are the results
and proposed decisions?
1. What was the methodology for the technology review?
Our technology review is focused on the identification and
evaluation of ``developments in practices, processes, and control
technologies'' since the promulgation of the MACT standards for the two
oil and gas source categories. If a review of available information
identifies such developments, then we conduct an analysis of the
technical feasibility of requiring the implementation of these
developments, along with the impacts (costs, emission reductions, risk
reductions, etc.). We then make a decision on whether it is necessary
to amend the regulation to require these developments.
Based on specific knowledge of each source category, we began by
identifying known developments in practices, processes and control
technologies. For the purpose of this exercise, we considered any of
the following to be a ``development'':
Any add-on control technology or other equipment that was
not identified and considered during MACT development;
Any improvements in add-on control technology or other
equipment (that was identified and considered during MACT development)
that could result in significant additional emission reduction;
Any work practice or operational procedure that was not
identified and considered during MACT development; and
Any process change or pollution prevention alternative
that could be broadly applied that was not identified and considered
during MACT development.
In addition to looking back at practices, processes or control
technologies reviewed at the time we developed the MACT standards, we
reviewed a variety of sources of data to aid in our evaluation of
whether there were additional practices, processes or controls to
consider. One of these sources of data was subsequent air toxics rules.
Since the promulgation of the MACT standards for the source categories
addressed in this proposal, the EPA has developed air toxics
regulations for a number of additional source categories. We reviewed
the regulatory requirements and/or technical analyses associated with
these subsequent regulatory actions to identify any practices,
processes and control technologies considered in these efforts that
could possibly be applied to emission sources in the source categories
under this current RTR review.
We also consulted the EPA's RBLC. The terms ``RACT,'' ``BACT,'' and
``LAER'' are acronyms for different program requirements under the CAA
provisions addressing the NAAQS. Control technologies classified as
RACT, BACT or LAER apply to stationary sources depending on whether the
source exists or is new and on the size, age and location of the
facility. The BACT and LAER (and sometimes RACT) are determined on a
case-by-case basis, usually by state or local permitting agencies. The
EPA established the RBLC to provide a central database of air pollution
technology information (including technologies required in source-
specific permits) to promote the sharing of information among
permitting agencies and to aid in identifying future possible control
technology options that might apply broadly to numerous sources within
a category or apply only on a source-by-source basis. The RBLC contains
over 5,000 air pollution control permit determinations that can help
identify appropriate technologies to mitigate many air pollutant
emission streams. We searched this database to determine whether any
practices, processes or control technologies are included for the types
of processes used for emission sources (e.g., spray booths) in the
source categories under consideration in this proposal.
We also consulted information from the Natural Gas STAR program.
The Natural Gas STAR program is a flexible, voluntary partnership that
encourages oil and natural gas companies to adopt cost effective
technologies and practices that improve operational efficiency and
reduce pollutant emissions. The program provides the oil and gas
industry with information on new techniques and developments to reduce
pollutant emissions from the various processes.
2. What are the results and proposed decisions from the technology
review?
There are three types of emission sources covered by the two oil
and gas NESHAP. These sources and the control technologies (including
add-on control devices and process modifications) considered during the
development of the MACT standards are: Glycol dehydrators (combustion
devices, recovery devices, process modifications), storage vessels with
the PFE (combustion devices, recovery devices) and equipment leaks
(LDAR programs, specific equipment modifications). Dehydrators are
addressed by both 40 CFR part 63, subpart HH and 40 CFR part 63,
subpart HHH, while equipment leaks and storage vessels with the PFE are
only covered by subpart HH.
Since the promulgation of 40 CFR part 63, subpart HH, which
established MACT standards to address HAP emissions from equipment
leaks at gas processing plants, the EPA has developed LDAR programs
that are more stringent than what is required in subpart HH. The most
prevalent differences between these more stringent programs and subpart
HH relate to the frequency of monitoring and the concentration which
constitutes a ``leak.'' We do consider these programs to represent a
development in practices and evaluated whether to revise the MACT
standards for equipment leaks at natural gas processing plants under
subpart HH in light of this development.
An analysis was performed above in section VI.B.1 to assess the VOC
reduction, costs and other impacts associated with these more stringent
LDAR program options at natural gas processing plants. One option
considered was to require compliance with 40 CFR part 60, subpart VVa
instead of 40 CFR part 60, subpart VV (the current NSPS requirement for
equipment leaks of VOC at natural gas processing plants), which changes
the leak definition (based on methane) from 10,000 ppm to 500 ppm and
requires monitoring of connectors. Because the current leak definition
under NESHAP 40 CFR part 63, subpart HH is the same as that in NSPS
subpart VV, and the ratio of VOC to HAP is approximately 20 to 1, we
expect that the HAP reduction would be 1/20th of the VOC reduction
under subpart VVa. The estimated incremental cost for that option was
determined to be $3,340 per ton of VOC. Based on the 20-to-1 ratio, we
estimate the incremental cost to control HAP at the subpart VVa level
would be approximately $66,800 per ton of HAP ($73,480/Mg). Other
options considered in section VI.B.1 of this preamble (and the
incremental cost of each option for reducing HAP) are as follows: The
use of an optical gas imaging camera monthly with an annual EPA Method
21 check ($129,000 per ton of HAP/$143,600 per Mg, if purchasing the
camera; $93,000 per ton of HAP/$103,300 per Mg, if renting the camera);
monthly optical gas imagining alone; and annual optical gas
imaging.\38\ In
[[Page 52785]]
light of the above, we do not believe that the additional costs of
these programs are justified.
---------------------------------------------------------------------------
\38\ As stated above in section VI.B.1, emissions for the two
options using the optical gas imaging camera alone cannot be
quantified and, therefore, no cost effectiveness values were
determined.
---------------------------------------------------------------------------
In addition to the plant-wide evaluations, a component analysis was
also evaluated at gas processing plants for the 40 CFR part 60, subpart
VVa-level of control (option 1 considered in section VI.B.1).\39\ That
assessment shows that the subpart VVa-level of control for connectors
has an incremental cost effectiveness of $4,360 per ton for VOC for
connectors and $144 per ton for VOC for valves. This means the
incremental cost to control HAP would be approximately $87,200 per ton
($96,900/Mg) for connectors and $2,880 per ton ($3,200/Mg) for valves.
We do not believe the additional cost for the more stringent
requirement for connectors is justified, but the additional cost for
valves is justified. Therefore, we are proposing to revise the
equipment leak requirements in 40 CFR part 63, subpart HH to lower the
leak definition for valves to an instrument reading of at least 500 ppm
as a result of our technology review.
---------------------------------------------------------------------------
\39\ Because optical gas imaging is used to view several pieces
of equipment at a facility at once to survey for leaks, options
involving imaging are not amenable to a component by component
analysis.
---------------------------------------------------------------------------
Some of the practices, processes or control technologies listed by
the Natural Gas STAR program applicable to the emission sources in
these categories were not identified and evaluated during the original
MACT development. While the Natural Gas STAR program does contain
information regarding new innovative techniques that are available to
reduce HAP emissions, they are not considered to have emission
reductions higher than what is set by the original MACT. One control
technology identified in the Natural Gas STAR program that would result
in no HAP emissions from glycol dehydration units would be the
replacement of a glycol dehydration unit with a desiccant dehydrator.
This technology cannot be used for natural gas operations with gas
streams having high temperature, high volume, and low pressure. Due to
the limitations posed by these conditions, we do not consider desiccant
dehydrators as MACT.
For storage vessels, the applicable technologies identified by the
Gas STAR program, which are evaluated above for proposal under NSPS in
section VI.B.4, are similar to the cover and control technologies
currently required for storage vessels under the existing MACT.
Therefore, these technologies would not result in any further emissions
reductions than what is achieved by the original MACT.
Our review of the RBLC did not identify any practices, processes
and control technologies applicable to the emission sources in these
categories that were not identified and evaluated during the original
MACT development. In light of the above, we are not proposing any
revisions to the existing MACT standards for storage vessels pursuant
to section 112(d)(6) of the CAA.
E. What other actions are we proposing?
1. Combustion Control Device Testing
As explained below in section VII.E.2, under our proposal,
performance testing would be required initially and every 5 years for
non-condenser control devices. However, for certain enclosed combustion
control devices, we are proposing to allow, as an alternative to on-
site testing, a performance test conducted by a control device
manufacturer in accordance with the procedures provided in this
proposal. We propose to allow a unit whose model meets the proposed
performance criteria to claim a BTEX or HAP destruction efficiency of
98 percent at the facility. This value is lower than the 99.9-percent
destruction efficiency required in the manufacturers' test due to
variations between the test fuel specified and the gas streams
combusted at the actual facility. A source subject to the small
dehydrator BTEX limit would use the 98-percent destruction efficiency
to calculate their dehydrator's BTEX emissions for the purpose of
demonstrating compliance. For the 95-percent control MACT standard, a
control device matching the tested model would be considered to meet
that requirement. Once a device has been demonstrated to meet the
proposed performance criteria (and, therefore, is assigned a 98-percent
destruction efficiency), installation of a unit matching the tested
model at a facility would require no further performance testing (i.e.,
periodic tests would not be required every 5 years).
We are proposing this alternative to minimize issues associated
with performance testing of certain combustion control devices. We
believe that testing units that are not configured with a distinct
combustion chamber present several technical issues that are more
optimally addressed through manufacturer testing, and once these units
are installed at a facility, through periodic inspection and
maintenance in accordance with manufacturers' recommendations. One
issue is that an extension above certain existing combustion control
device enclosures will be necessary to get adequate clearance above the
flame zone. Such extensions can more easily be configured by the
manufacturer of the control device rather than having to modify an
extension in the field to fit devices at every site. Issues related to
transporting, installing and supporting the extension in the field are
also eliminated through manufacturer testing. Another concern is that
the pitot tube used to measure flow can be altered by radiant heat from
the flame such that gas flow rates are not accurate. This issue is best
overcome by having the manufacturer select and use the pitot tube best
suited to their specific unit. For these reasons, we believe the
manufacturers' test is appropriate for these control devices with
ongoing performance ensured by periodic inspection and maintenance.
This proposed alternative does not apply to flares, as defined in
40 CFR 63.761 and 40 CFR 63.1271, which must demonstrate compliance by
meeting the design and operation requirements in 40 CFR 63.11(b), 40
CFR 63.772(e)(2) and 40 CFR 63.1282(d)(2). It also would not apply to
thermal oxidizers having a combustion chamber/firebox where combustion
temperature and residence time can be measured during an on-site
performance test and are valid indicators of performance. These thermal
oxidizers do not present the issues described above relative to on-site
performance testing and, therefore, do not need an alternative testing
option. The proposed alternative would, therefore, apply to enclosed
combustion control devices except for these thermal oxidizers.
In conjunction with the proposed manufacturer testing alternative,
we are proposing to add a definition for flare to clarify that flares,
as referenced in the NESHAP (and to which the proposed testing
alternative does not apply), refers to a thermal oxidation system with
an open flame (i.e., without enclosure). Accordingly, any thermal
oxidation system that does not meet the proposed flare definition would
be considered an enclosed combustion control device.
We estimate that there are many existing facilities currently using
enclosed combustion control devices that would be required to either
conduct an on-site performance test or install and operate a control
device tested by the manufacturer under our proposal. Given the
estimated number of these combustion control devices in use, the time
required for manufacturers to test and manufacture such units, we are
proposing that existing sources have up to 3 years from the date of the
final rules' publication date to comply with
[[Page 52786]]
the initial performance testing requirements.
2. Monitoring, Recordkeeping and Reporting
We are proposing to make changes to the monitoring requirements
described below to address issues we have identified through a
monitoring sufficiency review performed during the RTR process. First,
we are including calibration procedures associated with parametric
monitoring requirements in the existing NESHAP. The NESHAP require
parametric monitoring of control device parameters (e.g., temperatures
or flowrate monitoring), but did not include information on calibration
or included inadequate information on calibration of monitoring
devices. Therefore, we are specifying the calibration requirements for
temperature and flow monitors that the NESHAP currently lacks.
In addition, under the current NESHAP, a design analysis can be
used in lieu of performance testing to demonstrate compliance and
establish operating parameter limits. We are proposing to allow the use
of the design evaluation alternative only when the control device being
used is a condenser. The design evaluation option is appropriate for
condensers because their emissions can be accurately predicted using
readily available physical property information (e.g., vapor pressure
data and condensation calculations). In those cases, one would not need
to conduct emissions testing to determine actual emissions to
demonstrate compliance with the MACT standard. For example, a
requirement that ``the temperature at the outlet of the condenser shall
be maintained at 50[deg] Fahrenheit below the condensation temperature
calculated for the compound of interest using the reference equation''
(e.g., National Institute of Standards and Technology Chemistry WebBook
at http://webbook.nist.gov/chemistry/) is adequate to assure proper
operation of the condenser and, therefore, compliance with the required
emission standard.
For other types of control technologies, such as carbon adsorption
systems and enclosed combustion devices,\40\ the ability to predict
emissions depends on data developed by the vendor and such data may not
reliably result in an accurate prediction of emissions from a specific
facility. There are variables (e.g., air to fuel ratios and waste
constituents for combustion; varying organic concentrations,
constituents and capacity issues, including break-through for carbon
adsorption) that make theoretical predictions less reliable. The
effects of these site-specific variables on emissions are not easily
predictable and establishing monitoring conditions (e.g., combustion
temperature, vacuum regeneration) based on vendor data will likely not
account for those variables. Therefore, we propose to eliminate the
design evaluation alternative for non-condenser controls.
---------------------------------------------------------------------------
\40\ The design analysis alternative in the existing MACT does
not apply to flares. As previously mentioned, the existing MACT
provides separate design and operation requirements for flares.
---------------------------------------------------------------------------
For non-condenser controls (and condensers not using the design
analysis option), in addition to the initial compliance testing, we are
proposing that performance tests be conducted at least once every 5
years and whenever sources desire to establish new operating limits.
Under the current NESHAP, a performance test is only conducted in two
instances: (1) As an alternative to a design analysis for their
compliance demonstration and identification of operating parameter
ranges and (2) as a requirement to resolve a disagreement between the
EPA and the owner or operator regarding the design analysis. The
current NESHAP do not require additional performance testing beyond
these two cases (i.e., there is no periodic testing requirement). As
mentioned above, we are proposing to remove the design evaluation
option for non-condenser controls. For non-condenser controls (and
condensers not using the design analysis option), the proposed periodic
testing would ensure compliance with the emission standards by
verifying that the control device is meeting the necessary HAP
destruction efficiency determined in the initial performance test. As
discussed above in section VII.E.1, we are proposing that combustion
control devices tested under the manufacturers' procedure are not
required to conduct periodic testing. In addition, we are also
proposing that combustion control devices that can demonstrate a
uniform combustion zone temperature meeting the required control
efficiency during the initial performance test are exempt from periodic
testing. The requirement for continuous monitoring of combustion zone
temperature is an accurate indicator of control device performance and
eliminates the need for future testing.
The current NESHAP (40 CFR 63.771(d) and 40 CFR 63.1281(d)) require
operating an enclosed combustion device at a minimum residence time of
0.5 seconds at a minimum temperature of 760 degrees Celsius. We are
proposing to remove the residence time requirement. The residence time
requirement is not needed because the compliance demonstration made
during the performance test is sufficient to ensure that the combustion
device has adequate residence time to ensure the needed destruction
efficiency. Therefore, we are proposing to remove the residence time
requirement.
We are also clarifying at 40 CFR 63.773(d)(3)(i) and 40 CFR
63.1283(d)(3)(i) for thermal vapor incinerators, boilers and process
heaters, that the temperature sensor shall be installed at a location
representative of the combustion zone temperature. Currently, the
regulation requires that the temperature sensor be installed at a
location ``downstream of the combustion zone'' because we had thought
that the temperature downstream would be representative of combustion
zone temperature. We have now learned that may or may not be the case.
We are, therefore, proposing to amend this provision to more accurately
reflect the intended requirement.
Next, consistent with revisions for SSM, we've revised 40 CFR
63.771(d)(4)(i) and 40 CFR 63.1281(d)(4)(i), except when maintenance or
repair on a unit cannot be completed without a shutdown of the control
device.
Also, we've updated the criteria for prior performance test results
that can be used to demonstrate compliance in lieu of conducting a
performance test. These updates ensure that data for determining
compliance are accurate, up-to-date, and truly representative of actual
operating conditions.
In addition, we are proposing to revise the temperature monitoring
device minimum accuracy criteria in 40 CFR 63.773(d)(3)(i) to better
reflect the level of performance that is required of the temperature
monitoring devices. We believe that temperature monitoring devices
currently used to meet the requirements of the NESHAP can meet the
proposed revised criteria without modification.
Also, we are proposing to revise the calibration gas concentration
for the no detectable emissions procedure applicable to closed vent
systems in 40 CFR 63.772(c)(4)(ii) from 10,000 ppmv to 500 ppmv methane
to be consistent with the leak threshold of 500 ppmv in 40 CFR part 63,
subpart HH. The current calibration level is inconsistent with
achieving accurate readings at the level necessary to demonstrate there
are no detectable emissions.
[[Page 52787]]
Also, we are proposing recordkeeping and reporting requirements for
carbon adsorption systems. The current NESHAP require the replacement
of all carbon in the carbon adsorption system with fresh carbon on a
regular, predetermined time interval that is no longer than the carbon
service life established for the carbon system, but provide no
recordkeeping or reporting requirement to document and assure
compliance with this standard. We believe that maintaining some sort of
log book is a reasonable alternative combined with a requirement to
report instances when specified practices are not followed. Therefore,
the proposed rule adds reporting and recordkeeping requirements for
establishing a schedule and maintaining logs of carbon replacement.
Finally, as noted above in section VII.B.1, we are proposing a BTEX
emissions limit for small glycol dehydration unit process vents. For
the compliance demonstration, we propose that parametric monitoring of
the control device be performed. We believe that parametric monitoring
is adequate for glycol dehydrators in these two source categories
because temperature monitoring, whether it be to verify proper
condenser or combustion device operation, is a reliable indicator of
performance for reducing organic HAP emissions. We also considered the
use of a continuous emissions monitoring system (CEMS) to monitor
compliance. However, for glycol dehydrators in the oil and natural gas
sector, the necessary electricity, weather-protective enclosures and
daily staffing are not usually available. We, therefore, question the
technical feasibility of operating a CEMS correctly in this sector. We
request comment on the practicality of including provisions in the
final rule for a CEMS to monitor BTEX emissions for small glycol
dehydration units.
3. Startup, Shutdown, Malfunction
The United States Court of Appeals for the District of Columbia
Circuit vacated portions of two provisions in the EPA's CAA section 112
regulations governing the emissions of HAP during periods of SSM.
Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), cert. denied, 130
S. Ct. 1735 (U.S. 2010). Specifically, the Court vacated the SSM
exemption contained in 40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), that is
part of a regulation, commonly referred to as the General Provisions
Rule, that the EPA promulgated under section 112 of the CAA. When
incorporated into CAA section 112(d) regulations for specific source
categories, these two provisions exempt sources from the requirement to
comply with the otherwise applicable CAA section 112(d) emission
standard during periods of SSM.
We are proposing the elimination of the SSM exemption in the two
oil and gas NESHAP. Consistent with Sierra Club v. EPA, the EPA is
proposing to apply the standards in these NESHAP at all times. In
addition, we are proposing to revise 40 CFR 63.771(d)(4)(i) and 40 CFR
63.1281(d)(4)(i) to remove the provision allowing shutdown of the
control device during maintenance or repair. We are also proposing
several revisions to the General Provisions applicability table for the
MACT standard. For example, we are proposing to eliminate the
incorporation of the General Provisions' requirement that the source
develop a SSM plan. We are also proposing to eliminate or revise
certain recordkeeping and reporting requirements related to the SSM
exemption. The EPA has attempted to ensure that we have not included in
the proposed regulatory language any provisions that are inappropriate,
unnecessary or redundant in the absence of the SSM exemption. We are
specifically seeking comment on whether there are any such provisions
that we have inadvertently incorporated or overlooked.
In proposing the MACT standards in these rules, the EPA has taken
into account startup and shutdown periods. We believe that operations
and emissions do not differ from normal operations during these periods
such that it warrants a separate standard. Therefore, we have not
proposed different standards for these periods.
Periods of startup, normal operations and shutdown are all
predictable and routine aspects of a source's operations. However, by
contrast, malfunction is defined as a ``sudden, infrequent and not
reasonably preventable failure of air pollution control and monitoring
equipment, process equipment or a process to operate in a normal or
usual manner * * *'' (40 CFR 63.2). The EPA has determined that
malfunctions should not be viewed as a distinct operating mode and,
therefore, any emissions that occur at such times do not need to be
factored into development of CAA section 112(d) standards, which, once
promulgated, apply at all times. In Mossville Environmental Action Now
v. EPA, 370 F.3d 1232, 1242 (D.C. Cir. 2004), the Court upheld as
reasonable, standards that had factored in variability of emissions
under all operating conditions. However, nothing in CAA section 112(d)
or in case law requires that the EPA anticipate and account for the
innumerable types of potential malfunction events in setting emission
standards. See Weyerhaeuser v. Costle, 590 F.2d 1011, 1058 (D.C. Cir.
1978), (``In the nature of things, no general limit, individual permit,
or even any upset provision can anticipate all upset situations. After
a certain point, the transgression of regulatory limits caused by
``uncontrollable acts of third parties,'' such as strikes, sabotage,
operator intoxication or insanity, and a variety of other
eventualities, must be a matter for the administrative exercise of
case-by-case enforcement discretion, not for specification in advance
by regulation.'').
Further, it is reasonable to interpret CAA section 112(d) as not
requiring the EPA to account for malfunctions in setting emissions
standards. For example, we note that CAA section 112 uses the concept
of ``best performing'' sources in defining MACT, the level of
stringency that major source standards must meet. Applying the concept
of ``best performing'' to a source that is malfunctioning presents
significant difficulties. The goal of best performing sources is to
operate in such a way as to avoid malfunctions of their units.
Moreover, even if malfunctions were considered a distinct operating
mode, we believe it would be impracticable to take malfunctions into
account in setting CAA section 112(d) standards for oil and natural gas
production facility and natural gas transmission and storage
operations. As noted above, by definition, malfunctions are sudden and
unexpected events, and it would be difficult to set a standard that
takes into account the myriad different types of malfunctions that can
occur across all sources in each source category. Moreover,
malfunctions can also vary in frequency, degree and duration, further
complicating standard setting.
In the event that a source fails to comply with the applicable CAA
section 112(d) standards as a result of a malfunction event, the EPA
would determine an appropriate response based on, among other things,
the good faith efforts of the source to minimize emissions during
malfunction periods, including preventative and corrective actions, as
well as root cause analyses to ascertain and rectify excess emissions.
The EPA would also consider whether the source's failure to comply with
the CAA section 112(d) standard was, in fact, ``sudden, infrequent, not
reasonably preventable'' and was not instead ``caused in part by poor
maintenance or careless operation.'' 40 CFR 63.2 (definition of
malfunction).
[[Page 52788]]
Finally, the EPA recognizes that even equipment that is properly
designed and maintained can sometimes fail and that such failure can
sometimes cause or contribute to an exceedance of the relevant emission
standard. (See, e.g., State Implementation Plans: Policy Regarding
Excessive Emissions During Malfunctions, Startup, and Shutdown
(September 20, 1999); Policy on Excess Emissions During Startup,
Shutdown, Maintenance, and Malfunctions (February 15, 1983)). The EPA
is, therefore, proposing to add to the final rule an affirmative
defense to civil penalties for exceedances of emission limits that are
caused by malfunctions in both of the MACT standards addressed in this
proposal. See 40 CFR 63.761 for sources subject to the oil and natural
gas production MACT standards, or 40 CFR 63.1271 for sources subject to
the natural gas transmission and storage MACT standards (defining
``affirmative defense'' to mean, in the context of an enforcement
proceeding, a response or defense put forward by a defendant, regarding
which the defendant has the burden of proof and the merits of which are
independently and objectively evaluated in a judicial or administrative
proceeding). We also are proposing other regulatory provisions to
specify the elements that are necessary to establish this affirmative
defense; a source subject to the oil and natural gas production
facilities or natural gas transmission MACT standards must prove by a
preponderance of the evidence that it has met all of the elements set
forth in 40 CFR 63.762 and a source subject to the natural gas
transmission and storage facilities MACT standards must prove by a
preponderance of the evidence that it has met all of the elements set
forth in 40 CFR 63.1272. (See 40 CFR 22.24.) The criteria ensure that
the affirmative defense is available only where the event that causes
an exceedance of the emission limit meets the narrow definition of
malfunction in 40 CFR 63.2 (sudden, infrequent, not reasonably
preventable and not caused by poor maintenance and or careless
operation). For example, to successfully assert the affirmative
defense, the source must prove by a preponderance of evidence that
excess emissions ``[w]ere caused by a sudden, infrequent, and
unavoidable failure of air pollution control and monitoring equipment,
process equipment, or a process to operate in a normal or usual manner
* * *.'' The criteria also are designed to ensure that steps are taken
to correct the malfunction, to minimize emissions in accordance with 40
CFR 63.762 for sources subject to the oil and natural gas production
facilities MACT standards or 40 CFR 63.1272 for sources subject to the
natural gas transmission and storage facilities MACT standards and to
prevent future malfunctions. For example, the source must prove by a
preponderance of evidence that ``[r]epairs were made as expeditiously
as possible when the applicable emission limitations were being
exceeded * * *'' and that ``[a]ll possible steps were taken to minimize
the impact of the excess emissions on ambient air quality, the
environment and human health * * *.'' In any judicial or administrative
proceeding, the Administrator may challenge the assertion of the
affirmative defense and, if the respondent has not met its burden of
proving all of the requirements in the affirmative defense, appropriate
penalties may be assessed in accordance with section 113 of the CAA
(see also 40 CFR 22.77).
4. Applicability and Compliance
a. Calculating Potential To Emit (PTE)
We are proposing to amend section 40 CFR 63.760(a)(1)(iii) to
clarify that sources must use a glycol circulation rate consistent with
the definition of PTE in 40 CFR 63.2 in calculating emissions for
purposes of determining PTE. Affected parties have misinterpreted the
current language concerning measured values or annual average to apply
to a broader range of parameters than was intended. Those qualifiers
were meant to apply to gas characteristics that are measured, such as
inlet gas composition, pressure and temperature rather than process
equipment settings. That means that the circulation rate used in PTE
determinations shall be the maximum under its physical and operational
design.
In addition to the proposed changes described above, we are seeking
comment on several PTE related issues. According to the data available
to the Administrator, when 40 CFR part 63, subpart HH was promulgated,
the level of HAP emissions was predominantly driven by natural gas
throughput (i.e., HAP emissions went up or down in concert with natural
gas throughput). Since promulgation, we have learned that there is not
always a direct correlation between HAP emissions and natural gas
throughput. We have received information suggesting that, in some
cases, HAP emissions can increase despite decreasing natural gas
throughput due to changes in gas composition. We are asking for comment
regarding the likelihood of this occurrence and data demonstrating the
circumstances where it occurs. In light of the potential issue, we are
asking for comment regarding the addition of provisions in the NESHAP
to require area sources to recalculate their PTE to confirm that they
are indeed area sources and whether that calculation should be
performed on an annual or biannual basis to verify that changes in gas
composition have not increased their emissions.
b. Definition of Facility and Applicability Criteria
Subpart HH of 40 CFR part 63 (section 63.760(a)(2)) currently
defines facilities as those where hydrocarbon liquids are processed,
upgraded or stored prior to the point of custody transfer or where
natural gas is processed, upgraded or stored prior to entering the
Natural Gas Transmission and Storage source category. We are proposing
to remove the references to ``point of custody transfer'' and
``transmission and storage source categories'' from the definition
because the operations performed at a site sufficiently define a
facility and the scope of the subpart is specified already under 40 CFR
63.760. In addition, we are removing the custody transfer reference
from the applicability criteria in 40 CFR 63.760(a)(2). Since
hydrocarbon liquids can pass through several custody transfer points
between the well and the final destination, the custody transfer
criteria is not clear enough. We are, therefore, proposing to replace
the reference to ``point of custody transfer'' with a more specific
description of the point up to which the subpart applies (i.e., the
point where hydrocarbon liquids enter either the organic liquids
distribution or petroleum refineries source categories) and exclude
custody transfer from that criteria. We believe this change eliminates
ambiguity and is consistent with the oil and natural gas production-
specific provisions in the organic liquids distribution MACT.
5. Other Proposed Changes To Clarify These Rules
The following lists additional changes to the NESHAP we are
proposing. This list includes proposed rule changes that address
editorial corrections and plain language revisions:
Revise 40 CFR 63.769(b) to clarify that the equipment leak
provisions in 40 CFR part 63, subpart HH do not apply to a source if
that source is required to control equipment leaks under either 40 CFR
part 63, subpart H or 40 CFR part 60, subpart KKK. The current 40 CFR
63.769(b), which states that subpart HH does not apply if a source
meets the
[[Page 52789]]
requirements in either of the subparts mentioned above, does not
clearly express our intent that such source must be implementing the
LDAR provisions in the other 40 CFR part 60 or 40 CFR part 63 subparts
to qualify for the exemption.
Revise 40 CFR 63.760(a)(1) to clarify that an existing
area source that increases its emissions to major source levels has up
to the first substantive compliance date to either reduce its emissions
below major source levels by obtaining a practically enforceable permit
or comply with the applicable major source provisions of 40 CFR part
63, subpart HH. We have revised the second to last sentence in 40 CFR
63.760(a)(1) by removing the parenthetical statement because it simply
reiterates the last sentence of this section and is, therefore,
unnecessary.
Revise 40 CFR 63.771(d)(1)(ii) and 40 CFR
63.1281(d)(1)(ii) to clarify that the vapor recovery device and ``other
control device'' described in those provisions refer to non-destructive
control devices only.
Revise the last sentence of 40 CFR 63.764(i) and 40 CFR
63.1274(g) to clarify the requirements following an unsuccessful
attempt to repair a leak.
Updated the e-mail and physical address for area source
reporting in 40 CFR 63.775(c)(1).
VIII. What are the cost, environmental, energy and economic impacts of
the proposed 40 CFR part 60, subpart OOOO and amendments to subparts HH
and HHH of 40 CFR part 63?
We are presenting a combined discussion of the estimates of the
impacts for the proposed 40 CFR part 60, subpart OOOO and proposed
amendments to 40 CFR part 63, subpart HH and 40 CFR part 63, subpart
HHH. The cost, environmental and economic impacts presented in this
section are expressed as incremental differences between the impacts of
an oil and natural gas facility complying with the amendments to
subparts HH and HHH and new standards under 40 CFR 60, subpart OOOO and
the baseline, i.e., the standards before these amendments. The impacts
are presented for the year 2015, which will be the year that all
existing oil and natural gas facilities will have to be in compliance,
and also the year that will represent approximately 5 years of
construction of new oil and natural gas facilities subject to the NSPS
emissions limits. The analyses and the documents referenced below can
be found in Docket ID Numbers EPA-HQ-OAR-2007-0877 and EPA-HQ-OAR-2002-
0051.
A. What are the affected sources?
We expect that by 2015, the year when all existing sources will be
required to come into compliance in the United States, there will be 97
oil and natural gas production facilities and 15 natural gas
transmission and storage facilities with one or more existing glycol
dehydration units. We also estimate that there will be an additional
329 (there are 47 facilities that already have an affected glycol
dehydration unit) existing oil and natural gas production facilities
with existing storage vessels that we expect to be affected by these
final amendments. These facilities operate approximately 134 glycol
dehydration units (115 in production and 19 in transmission and
storage) and 1,970 storage vessels. Approximately 10 oil and natural
gas production and two transmission and storage facilities would have
new glycol dehydration units and 38 production facilities would have
new dehydration units. We expect new production facilities would
operate approximately 12 production glycol dehydration units and 197
storage vessels and new transmission and storage would operate
approximately two glycol dehydration units.
Based on data provided by the United States Energy Information
Administration, we anticipate that by 2015 there will be approximately
21,800 gas wellhead facilities, 790 reciprocating compressors, 30
centrifugal compressors, 14,000 pneumatic devices and 300 storage
vessels subject to the new NSPS for VOC. Some of these affected
facilities will be built at existing facilities and some at new
greenfield facilities. Based on data limitations, we assume impacts are
equal regardless of location.
There are about 21 glycol dehydration units with high enough HAP
emissions that we believe cannot meet the emissions limit without using
more than one control technique. In developing the cost impacts, we
assume that they would require multiple controls. The controls for
which we have detailed cost data are condensers and VRU, so we
developed costs for both controls to develop what we consider to be a
reasonable cost estimate for these facilities. This does not imply that
we believe these facilities will specifically use a combination of a
condenser and vapor recovery limit, but we do believe the combination
of these control results is a reasonable estimate of cost.
B. How are the impacts for this proposal evaluated?
For these proposed Oil and Natural Gas Production and Natural Gas
Transmission and Storage NESHAP amendments and NSPS, the EPA used two
models to evaluate the impacts of the regulation on the industry and
the economy. Typically, in a regulatory analysis, the EPA determines
the regulatory options suitable to meet statutory obligations under the
CAA. Based on the stringency of those options, the EPA then determines
the control technologies and monitoring requirements that sources might
rationally select to comply with the regulation. This analysis is
documented in an engineering analysis. The selected control
technologies and monitoring requirements are then evaluated in a cost
model to determine the total annualized control costs. The annualized
control costs serve as inputs to an Economic Impact Analysis model that
evaluates the impacts of those costs on the industry and society as a
whole.
The Economic Impact Analysis used the National Energy Modeling
System (NEMS) to estimate the impacts of the proposed NSPS on the
United States energy system. The NEMS is a publically-available model
of the United States energy economy developed and maintained by the
Energy Information Administration of the United States DOE and is used
to produce the Annual Energy Outlook, a reference publication that
provides detailed forecasts of the energy economy from the current year
to 2035. The impacts we estimated included changes in drilling
activity, price and quantity changes in the production and consumption
of crude oil and natural gas and changes in international trade of
crude oil and natural gas. We evaluated whether and to what extent the
increased production costs imposed by the NSPS might alter the mix of
fuels consumed at a national level. Additionally, we combined estimated
emissions co-reductions of methane from the engineering analysis with
NEMS analysis to estimate the net change in CO2e GHG from
energy-related sources.
C. What are the air quality impacts?
For the oil and natural gas sector NESHAP and NSPS, we estimated
the emission reductions that will occur due to the implementation of
the final emission limits. The EPA estimated emission reductions based
on the control technologies selected by the engineering analysis. These
emission reductions associated with the proposed amendments to 40 CFR
part 63, subpart
[[Page 52790]]
HH and 40 CFR part 63, subpart HHH are based on the estimated
population in 2008. Under the proposed limits for glycol dehydration
units and storage vessels, we have estimated that the HAP emissions
reductions will be 1,400 tpy for existing units subject to the proposed
emissions limits.
For the NSPS, we estimated the emission reductions that will occur
due to the implementation of the final emission limits. The EPA
estimated emission reductions based on the control technologies
selected by the engineering analysis. These emission reductions are
based on the estimated population in 2015. Under the proposed NSPS, we
have estimated that the emissions reductions will be 540,000 tpy VOC
for affected facilities subject to the NSPS.
The control strategies likely adopted to meet the proposed NESHAP
amendments and the proposed NSPS will result in concurrent control of
HAP, methane and VOC emissions. We estimate that direct reductions in
HAP, methane and VOC for the proposed rules combined total about 38,000
tpy, 3.4 million tpy and 540,000 tpy, respectively.
Under the final standards, new monitoring requirements are being
added.
D. What are the water quality and solid waste impacts?
We estimated minimal water quality impacts for the proposed
amendments and proposed NSPS. For the proposed amendments to the
NESHAP, we anticipate that the water impacts associated with the
installation of a condenser system for the glycol dehydration unit
process 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, usually by
reinjection.
Similarly, the water impacts associated with installation of a
vapor control system either on a glycol dehydration unit or a storage
vessel would be minimal. This is because the water vapor collected
along with the 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 for reinjection.
There would be no water impacts expected for facilities subject to
the proposed NSPS. Further, we do not anticipate any adverse solid
waste impacts from the implementation of the proposed NESHAP amendments
and the proposed NSPS.
E. What are the secondary impacts?
Indirect or secondary air quality impacts include impacts that will
result from the increased electricity usage associated with the
operation of control devices, as well as water quality and solid waste
impacts (which were just discussed) that might occur as a result of
these proposed actions. We estimate the proposed amendments to 40 CFR
part 63, subpart HH and 40 CFR part 63, subpart HHH will increase
emissions of criteria pollutants due to the potential use of flares for
the control of storage vessels. We do not estimate an increased energy
demand associated with the installation of condensers, VRU or flares.
The increases in criteria pollutant emissions associated with the use
of flares to control storage vessels subject to existing source
standards are estimated to be 5,500 tpy of CO2, 16 tpy of
carbon monoxide (CO), 3 tpy of NOX, less than 1 tpy of
particulate matter (PM) and 6 tpy total hydrocarbons. For storage
vessels subject to new source standards, increases in secondary air
pollutants are estimated to be less than 900 tpy of CO2, 3
tpy of CO, 1 tpy of NOX, 1 tpy of PM and 1 tpy total
hydrocarbons.
In addition, we estimate that the secondary impacts associated with
the pneumatic controller requirements to comply with the proposed NSPS
would be about 22 tpy of CO2, 1 tpy of NOX and 3
tpy PM. For gas wellhead affected facilities, we estimate that the use
of flares would result in increases in criteria pollutant emissions of
about 990,000 tons of CO2, 2,800 tpy of CO, 500 tpy of
NOX, 5 tpy of PM and 1,000 tpy total hydrocarbons.
F. What are the energy impacts?
Energy impacts in this section are those energy requirements
associated with the operation of emission control devices. Potential
impacts on the national energy economy from the rule are discussed in
the economic impacts section. There would be little national energy
demand increase from the operation of any of the control options
analyzed under the proposed NESHAP amendments and proposed NSPS.
The proposed NESHAP amendments and proposed NSPS 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. We estimated that the proposed
standards will result in a net cost savings due to the recovery of
salable natural gas and condensate. Thus, the final standards have a
positive impact associated with the recovery of non-renewable energy
resources.
G. What are the cost impacts?
The estimated total capital cost to comply with the proposed
amendments to 40 CFR part 63, subpart HH for major sources in the Oil
and Natural Gas Production source category is approximately $51.5
million. The total capital cost for the proposed amendments to 40 CFR
part 63, subpart HHH for major sources in the Natural Gas Transmission
and Storage source category is estimated to be approximately $370
thousand. All costs are in 2008 dollars.
The total estimated net annual cost to industry to comply with the
proposed amendments to 40 CFR part 63, subpart HH for major sources in
the Oil and Natural Gas Production source category is approximately $16
million. The total net annual cost for proposed amendments to 40 CFR
part 63, subpart HHH for major sources in the Natural Gas Transmission
and Storage source category is estimated to be approximately $360,000.
These estimated annual costs include: (1) The cost of capital, (2)
operating and maintenance costs, (3) the cost of monitoring,
inspection, recordkeeping and reporting (MIRR) and (4) any associated
product recovery credits. All costs are in 2008 dollars.
The estimated total capital cost to comply with the proposed NSPS
is approximately $740 million in 2008 dollars. The total estimated net
annual cost to industry to comply with the proposed NSPS is
approximately $740 million in 2008 dollars. This annual cost estimate
includes: (1) The cost of capital, (2) operating and maintenance costs
and (3) the cost of MIRR. This estimated annual cost does not take into
account any producer revenues associated with the recovery of salable
natural gas and hydrocarbon condensates.
When revenues from additional product recovery are considered, the
proposed NSPS is estimated to result in a net annual engineering cost
savings overall. When including the additional natural gas recovery in
the engineering cost analysis, we assume that producers are paid $4 per
thousand cubic feet (Mcf) for the recovered gas at the wellhead. The
engineering analysis cost analysis assumes the value of recovered
condensate is $70 per barrel. Based on the engineering analysis, about
180,000,000 Mcf (180 billion cubic feet) of natural gas and 730,000
barrels of
[[Page 52791]]
condensate are estimated to be recovered by control requirements in
2015. Using the price assumptions, the estimated revenues from natural
gas product recovery are approximately $780 million in 2008 dollars.
This savings is estimated at $45 million in 2008 dollars.
Using the engineering cost estimates, estimated natural gas product
recovery, and natural gas product price assumptions, the net annual
engineering cost savings is estimated for the proposed NSPS at about
$45 million in 2008 dollars. Totals may not sum due to independent
rounding.
As the price assumption is very influential on estimated annualized
engineering costs, we performed a simple sensitivity analysis of the
influence of the assumed wellhead price paid to natural gas producers
on the overall engineering annualized costs estimate of the proposed
NSPS. At $4.22/Mcf, the price forecast reported in the 2011 Annual
Energy Outlook in 2008 dollars, the annualized costs are estimated at
about -$90 million, which would approximately double the estimate of
net cost savings of the proposed NSPS. As indicated by this difference,
EPA has chosen a relatively conservative assumption (leading to an
estimate of few savings and higher net costs) for the engineering costs
analysis. The natural gas price at which the proposed NSPS breaks-even
from an estimated engineering costs perspective is around $3.77/Mcf. A
$1/Mcf change in the wellhead natural gas price leads to about a $180
million change in the annualized engineering costs of the proposed
NSPS. Consequently, annualized engineering costs estimates would
increase to about $140 million under a $3/Mcf price or decrease to
about -$230 million under a $5/Mcf price. For further details on this
sensitivity analysis, please refer the regulatory impact analysis (RIA)
for this rulemaking located in the docket.
H. What are the economic impacts?
The NEMS analysis of energy system impacts for the proposed NSPS
option estimates that domestic natural gas production is likely to
increase slightly (about 20 billion cubic feet or 0.1 percent) and
average natural gas prices to decrease slightly ($0.04 per Mcf in 2008
dollars or 0.9 percent at the wellhead for onshore producers in the
lower 48 states) for 2015, the year of analysis. This increase in
production and decrease in wellhead price is largely a result of the
increased natural gas and condensate recovery as a result of complying
with the NSPS. Domestic crude oil production is not expected to change,
while average crude oil prices are estimated to decrease slightly
($0.02/barrel in 2008 dollars or less than 0.1 percent at the wellhead
for onshore producers in the lower 48 states) in the year of analysis,
2015. The NEMS-based analysis estimates in the year of analysis, 2015,
that net imports of natural gas and crude will not change
significantly.
Total CO2e emissions from energy-related sources are
expected to increase about 2.0 million metric tons CO2e or
0.04 percent under the proposed NSPS, according to the NEMS analysis.
This increase is attributable largely to natural gas consumption
increases. This estimate does not include CO2e reductions
from the implementation of the controls; these reductions are discussed
in more detail in the benefits section that follows.
We did not estimate the energy economy impacts of the proposed
NESHAP amendments using NEMS, as the expected costs of the rule are not
likely to have estimable impacts on the national energy economy.
I. What are the benefits?
The proposed Oil and Natural Gas NSPS and NESHAP amendments are
expected to result in significant reductions in existing emissions and
prevent new emissions from expansions of the industry. These proposed
rules combined are anticipated to reduce 38,000 tons of HAP, 540,000
tons of VOC and 3.4 million tons of methane. These pollutants are
associated with substantial health effects, welfare effects and climate
effects. With the data available, we are not able to provide credible
health benefit estimates for the reduction in exposure to HAP, ozone
and PM (2.5 microns and less) (PM2.5) for these rules, due
to the differences in the locations of oil and natural gas emission
points relative to existing information and the highly localized nature
of air quality responses associated with HAP and VOC reductions.
This is not to imply that there are no benefits of the rules;
rather, it is a reflection of the difficulties in modeling the direct
and indirect impacts of the reductions in emissions for this industrial
sector with the data currently available. In addition to health
improvements, there will be improvements in visibility effects,
ecosystem effects and climate effects, as well as additional product
recovery.
Although we do not have sufficient information or modeling
available to provide quantitative estimates for this rulemaking, we
include a qualitative assessment of the health effects associated with
exposure to HAP, ozone and PM2.5 in the RIA for this rule.
These qualitative effects are briefly summarized below, but for more
detailed information, please refer to the RIA, which is available in
the docket. One of the HAP of concern from the oil and natural gas
sector is benzene, which is a known human carcinogen, and formaldehyde,
which is a probable human carcinogen. VOC emissions are precursors to
both PM2.5 and ozone formation. As documented in previous
analyses (U.S. EPA, 2006 \41\ and U.S. EPA, 2010 \42\), exposure to
PM2.5 and ozone is associated with significant public health
effects. PM2.5 is associated with health effects such as
premature mortality for adults and infants, cardiovascular morbidity,
such as heart attacks, hospital admissions and respiratory morbidity
such as asthma attacks, acute and chronic bronchitis, hospital and
emergency room visits, work loss days, restricted activity days and
respiratory symptoms, as well as visibility impairment.\43\ Ozone is
associated with health effects such as respiratory morbidity such as
asthma attacks, hospital and emergency department visits, school loss
days and premature mortality, as well as injury to vegetation and
climate effects.\44\
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\41\ U.S. EPA. RIA. National Ambient Air Quality Standards for
Particulate Matter, Chapter 5. Office of Air Quality Planning and
Standards, Research Triangle Park, NC. October 2006. Available on
the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/Chapter%205-Benefits.pdf.
\42\ U.S. EPA. RIA. National Ambient Air Quality Standards for
Ozone. Office of Air Quality Planning and Standards, Research
Triangle Park, NC. January 2010. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/s1-supplemental_analysis_full.pdf.
\43\ U.S. EPA. Integrated Science Assessment for Particulate
Matter (Final Report). EPA-600-R-08-139F. National Center for
Environmental Assessment--RTP Division. December 2009. Available at
http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546.
\44\ U.S. EPA. Air Quality Criteria for Ozone and Related
Photochemical Oxidants (Final). EPA/600/R-05/004aF-cF. Washington,
DC: U.S. EPA. February 2006. Available on the Internet at
http:[sol][sol]cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923.
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In addition to the improvements in air quality and resulting
benefits to human health and non-climate welfare effects previously
discussed, this proposed rule is expected to result in significant
climate co-benefits due to anticipated methane reductions. Methane is a
potent GHG that, once emitted into the atmosphere, absorbs terrestrial
infrared radiation, which contributes to increased global warming and
continuing climate change. Methane reacts in the atmosphere to form
ozone and ozone also impacts global temperatures. According to the
[[Page 52792]]
Intergovernmental Panel on Climate Change (IPCC) 4th Assessment Report
(2007), methane is the second leading long-lived climate forcer after
CO2 globally. Total methane emissions from the oil and gas
industry represent about 40 percent of the total methane emissions from
all sources and account for about 5 percent of all CO2e
emissions in the United States, with natural gas systems being the
single largest contributor to United States anthropogenic methane
emissions.\45\ Methane, in addition to other GHG emissions, contributes
to warming of the atmosphere, which, over time, leads to increased air
and ocean temperatures, changes in precipitation patterns, melting and
thawing of global glaciers and ice, increasingly severe weather events,
such as hurricanes of greater intensity and sea level rise, among other
impacts.
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\45\ U.S. EPA (2011), 2011 U.S. Greenhouse Gas Inventory Report
Executive Summary available on the internet at
http:[sol][sol]www.epa.gov/climateexchange/emissions/downloads11/US-
GHG-Inventory-2011-Executive Summary.pdf.
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This rulemaking proposes emission control technologies and
regulatory alternatives that will significantly decrease methane
emissions from the oil and natural gas sector in the United States. The
regulatory alternatives proposed for the NESHAP and the NSPS are
expected to reduce methane emissions annually by about 3.4 million
short tons or 65 million metric tons CO2e. After considering
the secondary impacts of this proposal previously discussed, such as
increased CO2 emissions from well completion combustion and
decreased CO2e emissions because of fuel-switching by
consumers, the methane reductions become about 62 million metric tons
CO2e. These reductions represent about 26 percent of the
baseline methane emissions for this sector reported in the EPA's U.S.
Greenhouse Gas Inventory Report for 2009 (251.55 million metric tons
CO2e when petroleum refineries and petroleum transportation
are excluded because these sources are not examined in this proposal).
After considering the secondary impacts of this proposal, such as
increased CO2 emissions from well completion combustion and
decreased CO2 emissions because of fuel-switching by
consumers, the CO2e GHG reductions are reduced to about 62
million metric tons CO2e. However, it is important to note
that the emission reductions are based upon predicted activities in
2015; the EPA did not forecast sector-level emissions in 2015 for this
rulemaking. These emission reductions equate to the climate benefits of
taking approximately 11 million typical passenger cars off the road or
eliminating electricity use from about 7 million typical homes each
year.\46\
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\46\ U.S. EPA. Greenhouse Gas Equivalency Calculator available
at: http://www.epa.gov/cleanenergy/energy-resources/calculator.html
accessed 07/19/11.
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The EPA recognizes that the methane reductions proposed in this
rule will provide for significant economic climate benefits to society
just described. However, there is no interagency-accepted methodology
to place monetary values on these benefits. A `global warming potential
(GWP) approach' of converting methane to CO2e using the GWP
of methane provides an approximation method for estimating the
monetized value of the methane reductions anticipated from this rule.
This calculation uses the GWP of the non-CO2 gas to estimate
CO2 equivalents and then multiplies these CO2
equivalent emission reductions by the social cost of carbon developed
by the Interagency Social Cost of Carbon Work Group to generate
monetized estimates of the benefits.
The social cost of carbon is an estimate of the net present value
of the flow of monetized damages from a 1-metric ton increase in
CO2 emissions in a given year (or from the alternative
perspective, the benefit to society of reducing CO2
emissions by 1 ton). For more information about the social cost of
carbon, see the Support Document: Social Cost of Carbon for Regulatory
Impact Analysis Under Executive Order 12866 \47\ and RIA for the Light-
Duty Vehicle GHG rule.\48\ Applying this approach to the methane
reductions estimated for the proposed NESHAP and NSPS of the oil and
gas rule, the 2015 climate co-benefits vary by discount rate and range
from about $370 million to approximately $4.7 billion; the mean social
cost of carbon at the 3-percent discount rate results in an estimate of
about $1.6 billion in 2015.
---------------------------------------------------------------------------
\47\ Interagency Working Group on Social Cost of Carbon (IWGSC).
2010. Technical Support Document: Social Cost of Carbon for
Regulatory Impact Analysis Under Executive Order 12866. Docket ID
EPA-HQ-OAR-2009-0472-114577. http://www.epa.gov/otaq/climate/regulations/scc-tsd.pdf; Accessed March 30, 2011.
\48\ U.S. EPA. Final Rulemaking: Light-Duty Vehicle Greenhouse
Gas Emissions Standards and Corporate Average Fuel Economy
Standards. May 2010. Available on the Internet at http://www.epa.gov/otaq/climate/regulations.htm#finalR.
---------------------------------------------------------------------------
The ratio of domestic to global benefits of emission reductions
varies with key parameter assumptions. For example, with a 2.5 or 3
percent discount rate, the U.S. benefit is about 7-10 percent of the
global benefit, on average, across the scenarios analyzed.
Alternatively, if the fraction of GDP lost due to climate change is
assumed to be similar across countries, the domestic benefit would be
proportional to the U.S. share of global GDP, which is currently about
23 percent. On the basis of this evidence, values from 7 to 23 percent
should be used to adjust the global SCC to calculate domestic effects.
It is recognized that these values are approximate, provisional and
highly speculative. There is no a priori reason why domestic benefits
should be a constant fraction of net global damages over time.\49\
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\49\ Interagency Working Group on Social Cost of Carbon (IWGSC).
2010. Technical Support Document: Social Cost of Carbon for
Regulatory Impact Analysis Under Executive Order 12866.
---------------------------------------------------------------------------
These co-benefits equate to a range of approximately $110 to $1,400
per short ton of methane reduced, depending upon the discount rate
assumed with a per ton estimate of $480 at the 3-percent discount rate.
Methane climate co-benefit estimates for additional regulatory
alternatives are included in the RIA for this proposed rule. These
social cost of methane benefit estimates are not the same as would be
derived from direct computations (using the integrated assessment
models employed to develop the Interagency Social Cost of Carbon
estimates) for a variety of reasons, including the shorter atmospheric
lifetime of methane relative to CO2 (about 12 years compared
to CO2 whose concentrations in the atmosphere decay on
timescales of decades to millennia). The climate impacts also differ
between the pollutants for reasons other than the radiative forcing
profiles and atmospheric lifetimes of these gases.
Methane is a precursor to ozone and ozone is a short-lived climate
forcer that contributes to global warming. The use of the IPCC Second
Assessment Report GWP to approximate co-benefits may underestimate the
direct radiative forcing benefits of reduced ozone levels and does not
capture any secondary climate co-benefits involved with ozone-ecosystem
interactions. In addition, a recent EPA National Center of
Environmental Economics working paper suggests that this quick `GWP
approach' to benefits estimation will likely understate the climate
benefits of methane reductions in most cases.\50\ This conclusion is
reached using the 100-year GWP for methane of 25 as put forth in the
IPCC Fourth Assessment Report (AR 4), as opposed to the lower
[[Page 52793]]
value of 21 used in this analysis. Using the higher GWP estimate of 25
would increase these reported methane climate co-benefit estimates by
about 19 percent. Although the IPCC Assessment Report (AR4) suggested a
GWP of 25 for methane, the EPA has used GWP of 21 to estimate the
methane climate co-benefits for this oil and gas proposal in order to
provide estimates more consistent with global GHG inventories, which
currently use GWP from the IPCC Second Assessment Report.
---------------------------------------------------------------------------
\50\ Marten and Newbold (2011), Estimating the Social Cost of
Non-CO2 GHG Emissions: Methane and Nitrous Oxide, NCEE Working Paper
Series 11-01. http://yosemite.epa.gov/EE/epa/eed.nsf/WPNumber/2011-01?OpenDocument.
---------------------------------------------------------------------------
Due to the uncertainties involved with the `GWP approach' estimates
presented and methane climate co-benefits estimates available in the
literature, the EPA chooses not to compare these co-benefit estimates
to the costs of the rule for this proposal. Rather, the EPA presents
the `GWP approach' climate co-benefit estimates as an interim method to
produce these estimates until the Interagency Social Cost of Carbon
Work Group develops values for non-CO2 GHG. The EPA requests
comments from interested parties and the public about this interim
approach specifically and more broadly about appropriate methods to
monetize the climate benefits of methane reductions. In particular, the
EPA seeks public comments to this proposed rulemaking regarding social
cost of methane estimates that may be used to value the co-benefits of
methane emission reductions anticipated for the oil and gas industry
from this rule. Comments specific to whether GWP is an acceptable
method for generating a placeholder value for the social cost of
methane until interagency-modeled estimates become available are
welcome. Public comments may be provided in the official docket for
this proposed rulemaking in accordance with the process outlined
earlier in this notice. These comments will be considered in developing
the final rule for this rulemaking.
For the proposed NESHAP amendments, a break-even analysis suggests
that HAP emissions would need to be valued at $12,000 per ton for the
benefits to exceed the costs if the health, ecosystem and climate
benefits from the reductions in VOC and methane emissions are assumed
to be zero. Even though emission reductions of VOC and methane are co-
benefits for the proposed NESHAP amendments, they are legitimate
components of the total benefit-cost comparison. If we assume the
health benefits from HAP emission reductions are zero, the VOC
emissions would need to be valued at $1,700 per ton or the methane
emissions would need to be valued at $3,300 per ton for the co-benefits
to exceed the costs. All estimates are in 2008 dollars. For the
proposed NSPS, the revenue from additional product recovery exceeds the
costs, which renders a break-even analysis unnecessary when these
revenues are included in the analysis. Based on the methodology from
Fann, Fulcher, and Hubbell (2009),\51\ ranges of benefit-per-ton
estimates for emissions of VOC indicate that on average in the United
States, VOC emissions are valued from $1,200 to $3,000 per ton as a
PM2.5 precursor, but emission reductions in specific areas
are valued from $280 to $7,000 per ton in 2008 dollars. As a result,
even if VOC emissions from oil and natural gas operations result in
monetized benefits that are substantially below the national average,
there is a reasonable chance that the benefits of the rule would exceed
the costs, especially if we were able to monetize all of the additional
benefits associated with ozone formation, visibility, HAP and methane.
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\51\ Fann, N., C.M. Fulcher, B.J. Hubbell. The influence of
location, source, and emission type in estimates of the human health
benefits of reducing a ton of air pollution. Air Qual Atmos Health
(2009) 2:169-176.
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IX. Request for Comments
We are soliciting comments on all aspects of this proposed action.
All comments received during the comment period will be considered. In
addition to general comments on the proposed actions, we are also
interested in any additional data that may help to reduce the
uncertainties inherent in the risk assessments. We are specifically
interested in receiving corrections to the datasets used for MACT
analyses and risk modeling. Such data should include supporting
documentation in sufficient detail to allow characterization of the
quality and representativeness of the data or information. Please see
the following section for more information on submitting data.
X. Submitting Data Corrections
The facility-specific data used in the source category risk
analyses, facility-wide analyses and demographic analyses for each
source category subject to this action are available for download on
the RTR Web page at http://www.epa.gov/ttn/atw/rrisk/rtrpg.html. These
data files include detailed information for each HAP emissions release
point at each facility included in the source category and all other
HAP emissions sources at these facilities (facility-wide emissions
sources). However, it is important to note that the source category
risk analysis included only those emissions tagged with the MACT code
associated with the source category subject to the risk analysis.
If you believe the data are not representative or are inaccurate,
please identify the data in question, provide your reason for concern
and provide any ``improved'' data that you have, if available. When you
submit data, we request that you provide documentation of the basis for
the revised values to support your suggested changes. To submit
comments on the data downloaded from the RTR Web page, complete the
following steps:
1. Within this downloaded file, enter suggested revisions to the
data fields appropriate for that information. The data fields that may
be revised include the following:
------------------------------------------------------------------------
Data element Definition
------------------------------------------------------------------------
Control Measure................... Are control measures in place? (yes
or no).
Control Measure Comment........... Select control measure from list
provided and briefly describe the
control measure.
Delete............................ Indicate here if the facility or
record should be deleted.
Delete Comment.................... Describes the reason for deletion.
Emission Calculation Method Code Code description of the method used
for Revised Emissions. to derive emissions. For example,
CEM, material balance, stack test,
etc.
Emission Process Group............ Enter the general type of emission
process associated with the
specified emission point.
Fugitive Angle.................... Enter release angle (clockwise from
true North); orientation of the y-
dimension relative to true North,
measured positive for clockwise
starting at 0 degrees (maximum 89
degrees).
Fugitive Length................... Enter dimension of the source in the
east-west (x-) direction, commonly
referred to as length (ft).
[[Page 52794]]
Fugitive Width.................... Enter dimension of the source in the
north-south (y-) direction,
commonly referred to as width (ft).
Malfunction Emissions............. Enter total annual emissions due to
malfunctions (TPY).
Malfunction Emissions Max Hourly.. Enter maximum hourly malfunction
emissions here (lb/hr).
North American Datum.............. Enter datum for latitude/longitude
coordinates (NAD27 or NAD83); if
left blank, NAD83 is assumed.
Process Comment................... Enter general comments about process
sources of emissions.
REVISED Address................... Enter revised physical street
address for MACT facility here.
REVISED City...................... Enter revised city name here.
REVISED County Name............... Enter revised county name here.
REVISED Emission Release Point Enter revised Emission Release Point
Type. Type here.
REVISED End Date.................. Enter revised End Date here.
REVISED Exit Gas Flow Rate........ Enter revised Exit Gas Flowrate here
(ft\3\/sec).
REVISED Exit Gas Temperature...... Enter revised Exit Gas Temperature
here (OF).
REVISED Exit Gas Velocity......... Enter revised Exit Gas Velocity here
(ft/sec).
REVISED Facility Category Code.... Enter revised Facility Category Code
here, which indicates whether
facility is a major or area source.
REVISED Facility Name............. Enter revised Facility Name here.
REVISED Facility Registry Enter revised Facility Registry
Identifier. Identifier here, which is an ID
assigned by the EPA Facility
Registry System.
REVISED HAP Emissions Performance Enter revised HAP Emissions
Level Code. Performance Level here.
REVISED Latitude.................. Enter revised Latitude here (decimal
degrees).
REVISED Longitude................. Enter revised Longitude here
(decimal degrees).
REVISED MACT Code................. Enter revised MACT Code here.
REVISED Pollutant Code............ Enter revised Pollutant Code here.
REVISED Routine Emissions......... Enter revised routine emissions
value here (TPY).
REVISED SCC Code.................. Enter revised SCC Code here.
REVISED Stack Diameter............ Enter revised Stack Diameter here
(ft).
REVISED Stack Height.............. Enter revised Stack Height here
(Ft).
REVISED Start Date................ Enter revised Start Date here.
REVISED State..................... Enter revised state here.
REVISED Tribal Code............... Enter revised Tribal Code here.
REVISED Zip Code.................. Enter revised Zip Code here.
Shutdown Emissions................ Enter total annual emissions due to
shutdown events (TPY).
Shutdown Emissions Max Hourly..... Enter maximum hourly shutdown
emissions here (lb/hr).
Stack Comment..................... Enter general comments about
emission release points.
Startup Emissions................. Enter total annual emissions due to
startup events (TPY).
Startup Emissions Max Hourly...... Enter maximum hourly startup
emissions here (lb/hr).
Year Closed....................... Enter date facility stopped
operations.
------------------------------------------------------------------------
2. Fill in the commenter information fields for each suggested
revision (i.e., commenter name, commenter organization, commenter e-
mail address, commenter phone number and revision comments).
3. Gather documentation for any suggested emissions revisions
(e.g., performance test reports, material balance calculations, etc.).
4. Send the entire downloaded file with suggested revisions in
Microsoft[supreg] Access format and all accompanying documentation to
Docket ID Number EPA-HQ-OAR-2010-0505 (through one of the methods
described in the ADDRESSES section of this preamble). To expedite
review of the revisions, it would also be helpful if you submitted a
copy of your revisions to the EPA directly at [email protected] in addition
to submitting them to the docket.
5. If you are providing comments on a facility with multiple source
categories, you need only submit one file for that facility, which
should contain all suggested changes for all source categories at that
facility. We request that all data revision comments be submitted in
the form of updated Microsoft[supreg] Access files, which are provided
on the http://www.epa.gov/ttn/atw/rrisk/rtrpg.html Web page.
XI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
Under Executive Order 12866 (58 FR 51735, October 4, 1993), this
action is an ``economically significant regulatory action'' because it
is likely to have an annual effect on the economy of $100 million or
more. Accordingly, the EPA submitted this action to OMB for review
under Executive Order 12866 and Executive Order 13563 (76 FR 3821,
January 21, 2011) and any changes made in response to OMB
recommendations have been documented in the docket for this action.
In addition, the EPA prepared a RIA of the potential costs and
benefits associated with this action. The RIA available in the docket
describes in detail the empirical basis for the EPA's assumptions and
characterizes the various sources of uncertainties affecting the
estimates below. Table 8 shows the results of the cost and benefits
analysis for these proposed rules. For more information on the benefit
and cost analysis, as well as details on the regulatory options
considered, please refer to the RIA for this rulemaking, which is
available in the docket.
[[Page 52795]]
Table 8--Summary of the Monetized Benefits, Costs and Net Benefits for the Proposed Oil and Natural Gas NSPS and
NEHSAP Amendments in 2015
[Millions of 2008$] \1\
----------------------------------------------------------------------------------------------------------------
Proposed NSPS and
Proposed NSPS Proposed NESHAP NESHAP amendments
amendments combined
----------------------------------------------------------------------------------------------------------------
Total Monetized Benefits \2\........ N/A N/A N/A.
Total Costs \3\..................... -$45 million $16 million -$29 million.
Net Benefits........................ N/A N/A N/A.
Non-monetized Benefits 4 5.......... 37,000 tons of HAP 1,400 tons of HAP 38,000 tons of HAP.
540,000 tons of VOC 9,200 tons of VOC 540,000 tons of VOC.
3.4 million tons of 4,900 tons of methane 3.4 million tons of
methane methane.
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Health effects of HAP exposure.
Health effects of PM2.5 and ozone exposure.
Visibility impairment.
Vegetation effects.
Climate effects.
----------------------------------------------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2015).
\2\ While we expect that these avoided emissions will result in improvements in air quality and reductions in
health effects associated with HAP, ozone and PM, as well as climate effects associated with methane, we have
determined that quantification of those benefits cannot be accomplished for this rule in a defensible way.
This is not to imply that there are no benefits of the rules; rather, it is a reflection of the difficulties
in modeling the direct and indirect impacts of the reductions in emissions for this industrial sector with the
data currently available.
\3\ The engineering compliance costs are annualized using a 7-percent discount rate. The negative cost for the
proposed NSPS reflects the inclusion of revenues from additional natural gas and hydrocarbon condensate
recovery that are estimated as a result of the proposed NSPS.
\4\ For the NSPS, reduced exposure to HAP and climate effects are co-benefits. For the NESHAP, reduced VOC
emissions, PM2.5 and ozone exposure, visibility and vegetation effects and climate effects are co-benefits.
\5\ The specific control technologies for these proposed rules are anticipated to have minor secondary
disbenefits. The net CO2-equivalent emission reductions are 93,000 metric tons for the NESHAP and 62 million
metric tons for the NSPS.
B. Paperwork Reduction Act
The information collection requirements in this proposed action
have been submitted for approval to OMB under the Paperwork Reduction
Act, 44 U.S.C. 3501, et seq. The ICR document prepared by the EPA has
been assigned EPA ICR Numbers 1716.07 (40 CFR part 60, subpart OOOO),
1788.10 (40 CFR part 63, subpart HH), 1789.07 (40 CFR part 63, subpart
HHH) and 1086.10 (40 CFR part 60, subparts KKK and subpart LLL).
The information to be collected for the proposed NSPS and the
proposed NESHAP amendments are based on notification, recordkeeping and
reporting requirements in the NESHAP General Provisions (40 CFR part
63, subpart A), which are mandatory for all operators subject to
national emission standards. These recordkeeping and reporting
requirements are specifically authorized by section 114 of the CAA (42
U.S.C. 7414). All information submitted to the EPA pursuant to the
recordkeeping and reporting requirements for which a claim of
confidentiality is made is safeguarded according to Agency policies set
forth in 40 CFR part 2, subpart B.
These proposed rules would require maintenance inspections of the
control devices, but would not require any notifications or reports
beyond those required by the General Provisions. The recordkeeping
requirements require only the specific information needed to determine
compliance.
For sources subject to the proposed NSPS, burden changes associated
with these amendments result from the respondents' annual reporting and
recordkeeping burden associated with this proposed rule for this
collection (averaged over the first 3 years after the effective date of
the standards). The burden is estimated to be 560,000 labor hours at a
cost of $18 million per year. This includes the burden previously
estimated for sources subject to 40 CFR part 60, subpart KKK (which is
being incorporated into 40 CFR part 60, subpart OOOO). The average
hours and cost per regulated entity subject to the NSPS for oil and
natural gas production and natural gas transmissions and distribution
facilities would be 110 hours per response and $3,693 per response,
based on an average of 1,459 operators responding per year and 16
responses per year.
The estimated recordkeeping and reporting burden after the
effective date of the proposed amendments is estimated for all affected
major and area sources subject to the Oil and Natural Gas Production
NESHAP to be approximately 63,000 labor hours per year at a cost of
$2.1 million per year. For the Natural Gas Transmission and Storage
NESHAP, the recordkeeping and reporting burden is estimated to be 2,500
labor hours per year at a cost of $86,800 per year. This estimate
includes the cost of reporting, including reading instructions and
information gathering. Recordkeeping cost estimates include reading
instructions, planning activities and conducting compliance monitoring.
The average hours and cost per regulated entity subject to the Oil and
Natural Gas Production NESHAP would be 72 hours per year and $2,500 per
year, based on an average of 846 facilities per year and three
responses per facility. For the Natural Gas Transmission and Storage
NESHAP, the average hours and cost per regulated entity would be 50
hours per year and $1,600 per year, based on an average of 53
facilities per year and three responses per facility. Burden is defined
at 5 CFR 1320.3(b).
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 in 40 CFR are listed in 40 CFR part 9.
To comment on the Agency's need for this information, the accuracy
of the provided burden estimates and any suggested methods for
minimizing respondent burden, the EPA has established a public docket
for this rule, which includes this ICR, under Docket ID Number EPA-HQ-
OAR-2010-0505. Submit any comments related to the ICR to the EPA and
OMB. See the ADDRESSES section at the beginning of this notice for
where to submit comments to the
[[Page 52796]]
EPA. Send comments to OMB at the Office of Information and Regulatory
Affairs, Office of Management and Budget, 725 17th Street, NW.,
Washington, DC 20503, Attention: Desk Office for the EPA. Since OMB is
required to make a decision concerning the ICR between 30 and 60 days
after August 23, 2011, a comment to OMB is best assured of having its
full effect if OMB receives it by September 22, 2011. The final rule
will respond to any OMB or public comments on the information
collection requirements contained in this proposal.
C. Regulatory Flexibility Act
The Regulatory Flexibility Act generally requires an agency to
prepare a regulatory flexibility analysis of any rule subject to notice
and comment rulemaking requirements under the Administrative Procedure
Act or any other statute, unless the agency certifies that the rule
will not have a significant economic impact on a substantial number of
small entities (SISNOSE). Small entities include small businesses,
small organizations, and small governmental jurisdictions. For purposes
of assessing the impact of this rule on small entities, a small entity
is defined as: (1) A small business whose parent company has no more
than 500 employees (or revenues of less than $7 million for firms that
transport natural gas via pipeline); (2) a small governmental
jurisdiction that is a government of a city, county, town, school
district, or special district with a population of less than 50,000;
and (3) a small organization that is any not-for-profit enterprise
which is independently owned and operated and is not dominant in its
field.
Proposed NSPS
After considering the economic impact of the proposed NSPS on small
entities, I certify that this action will not have a SISNOSE. The EPA
performed a screening analysis for impacts on a sample of expected
affected small entities by comparing compliance costs to entity
revenues. Based upon the analysis in the RIA, which is in the Docket,
EPA concludes the number of impacted small businesses is unlikely to be
sufficiently large to declare a SISNOSE. Our judgment in this
determination is informed by the fact that many affected firms are
expected to receive revenues from the additional natural gas and
condensate recovery engendered by the implementation of the controls
evaluated in this RIA. As much of the additional natural gas recovery
is estimated to arise from completion-related activities, we expect the
impact on well-related compliance costs to be significantly mitigated.
This conclusion is enhanced because the returns to REC activities occur
without a significant time lag between implementing the control and
obtaining the recovered product, unlike many control options where the
emissions reductions accumulate over long periods of time; the reduced
emission completions and recompletions occur over a short span of time,
during which the additional product recovery is also accomplished.
Proposed NESHAP Amendments
After considering the economic impact of the proposed NESHAP
amendments on small entities, I certify that this action will not have
a SISNOSE. Based upon the analysis in the RIA, which is in the Docket,
we estimate that 62 of the 118 firms (53 percent) that own potentially
affected facilities are small entities. The EPA performed a screening
analysis for impacts on all expected affected small entities by
comparing compliance costs to entity revenues. Among the small firms,
52 of the 62 (84 percent) are likely to have impacts of less than 1
percent in terms of the ratio of annualized compliance costs to
revenues. Meanwhile, 10 firms (16 percent) are likely to have impacts
greater than 1 percent. Four of these 10 firms are likely to have
impacts greater than 3 percent. While these 10 firms might receive
significant impacts from the proposed NESHAP amendments, they represent
a very small slice of the oil and gas industry in its entirety, less
than 0.2 percent of the estimated 6,427 small firms in NAICS 211.
Although this final rule will not impact a substantial number of small
entities, the EPA, nonetheless, has tried to reduce the impact of this
rule on small entities by setting the final emissions limits at the
MACT floor, the least stringent level allowed by law.
We continue to be interested in the potential impacts of the
proposed rule on small entities and welcome comments on issues related
to such impacts.
D. Unfunded Mandates Reform Act
This action contains no Federal mandates under the provisions of
title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C.
1531-1538 for state, local or tribal governments or the private sector.
This proposed rule does not contain a Federal mandate that may result
in expenditures of $100 million or more for state, local and tribal
governments, in the aggregate, or to the private sector in any one
year. Thus, this proposed rule is not subject to the requirements of
sections 202 or 205 of UMRA. This proposed rule is also not subject to
the requirements of section 203 of UMRA because it contains no
regulatory requirements that might significantly or uniquely affect
small governments. This action contains no requirements that apply to
such governments nor does it impose obligations upon them.
E. Executive Order 13132: Federalism
This proposed rule does not have federalism implications. It will
not have substantial direct effects on the states, on the relationship
between the national government and the states, or on the distribution
of power and responsibilities among the various levels of government,
as specified in Executive Order 13132. Thus, Executive Order 13132 does
not apply to this proposed rule. In the spirit of Executive Order 13132
and consistent with the EPA policy to promote communications between
the EPA and state and local governments, the EPA specifically solicits
comment on this proposed rule from state and local officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). It will not have
substantial direct effect on tribal governments, on the relationship
between the Federal government and Indian tribes or on the distribution
of power and responsibilities between the Federal government and Indian
tribes, as specified in Executive Order 13175. Thus, Executive Order
13175 does not apply to this action.
The EPA specifically solicits additional comment on this proposed
action from tribal officials.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
This proposed rule is not subject to Executive Order 13045 (62 FR
19885, April 23, 1997) because the Agency does not believe the
environmental health risks or safety risks addressed by this action
present a disproportionate risk to children. This actions' health and
risk assessments are contained in section VII.C of this preamble.
The public is invited to submit comments or identify peer-reviewed
studies and data that assess effects of early life exposure to HAP from
oil and natural gas sector activities.
[[Page 52797]]
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution or Use
Executive Order 13211, (66 FR 28,355, May 22, 2001), provides that
agencies shall prepare and submit to the Administrator of the Office of
Information and Regulatory Affairs, OMB, a Statement of Energy Effects
for certain actions identified as significant energy actions. Section
4(b) of Executive Order 13211 defines ``significant energy actions'' as
``any action by an agency (normally published in the Federal Register)
that promulgates or is expected to lead to the promulgation of a final
rule or regulation, including notices of inquiry, advance notices of
proposed rulemaking, and notices of proposed rulemaking: (1)(i) That is
a significant regulatory action under Executive Order 12866 or any
successor order and (ii) is likely to have a significant adverse effect
on the supply, distribution, or use of energy; or (2) that is
designated by the Administrator of the Office of Information and
Regulatory Affairs as a significant energy action.''
The proposed rules will result in the addition of control equipment
and monitoring systems for existing and new sources within the oil and
natural gas industry. The proposed NESHAP amendments are unlikely to
have a significant adverse effect on the supply, distribution or use of
energy. As such, the proposed NESHAP amendments are not ``significant
energy actions'' as defined in Executive Order 13211 (66 FR 28355, May
22, 2001).
The proposed NSPS is also unlikely to have a significant effect on
the supply, distribution or use of energy. As such, the proposed NSPS
is not a ``significant energy action'' as defined in Executive Order
13211 (66 FR 28355, May 22, 2001). The basis for the determination is
as follows.
As discussed in the impacts section of the Preamble, we use the
NEMS to estimate the impacts of the proposed NSPS on the United States
energy system. The NEMS is a publically available model of the United
States energy economy developed and maintained by the Energy
Information Administration of the United States DOE and is used to
produce the Annual Energy Outlook, a reference publication that
provides detailed forecasts of the United States energy economy.
Proposed emission controls for the NSPS capture VOC emissions that
otherwise would be vented to the atmosphere. Since methane is co-
emitted with VOC, a large proportion of the averted methane emissions
can be directed into natural gas production streams and sold. One
pollution control requirement of the proposed NSPS also captures
saleable condensates. The revenues from additional natural gas and
condensate recovery are expected to offset the costs of implementing
the proposed NSPS.
The analysis of energy impacts for the proposed NSPS that includes
the additional product recovery shows that domestic natural gas
production is estimated to increase (20 billion cubic feet or 0.1
percent) and natural gas prices to decrease ($0.04/Mcf or 0.9 percent
at the wellhead for producers in the lower 48 states) in 2015, the year
of analysis. Domestic crude oil production is not estimated to change,
while crude oil prices are estimated to decrease slightly ($0.02/barrel
or less than 0.1 percent at the wellhead for producers in the lower 48
states) in 2015, the year of analysis. All prices are in 2008 dollars.
Additionally, the NSPS establishes several performance standards
that give regulated entities flexibility in determining how to best
comply with the regulation. In an industry that is geographically and
economically heterogeneous, this flexibility is an important factor in
reducing regulatory burden.
For more information on the estimated energy effects, please refer
to the economic impact analysis for this proposed rule. The analysis is
available in the RIA, which is in the public docket.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law No. 104-113 (15 U.S.C. 272 note)
directs the EPA to use voluntary consensus standards (VCS) in its
regulatory activities unless to do so would be inconsistent with
applicable law or otherwise impractical. VCS are technical standards
(e.g., materials specifications, test methods, sampling procedures, and
business practices) that are developed or adopted by VCS bodies. NTTAA
directs the EPA to provide Congress, through OMB, explanations when the
Agency decides not to use available and applicable VCS.
The proposed rule involves technical standards. Therefore, the
requirements of the NTTAA apply to this action. We are proposing to
revise 40 CFR part 63, subpart HH and 40 CFR part 63, subpart HHH to
allow ANSI/ASME PTC 19.10-1981, Flue and Exhaust Gas Analyses (Part 10,
Instruments and Apparatus) to be used in lieu of EPA Methods 3B, 6 and
16A. This standard is available from the American Society of Mechanical
Engineers (ASME), Three Park Avenue, New York, NY 10016-5990. Also, we
are proposing to revise subpart HHH to allow ASTM D6420-99 (2004), Test
Method for Determination of Gaseous Organic Compounds by Direct
Interface Gas Chromatography/Mass Spectrometry, to be used in lieu of
EPA Method 18. For a detailed discussion of this VCS, and its
appropriateness as a substitute for Method 18, see the final Oil and
Natural Gas Production NESHAP (Area Sources) (72 FR 36, January 3,
2007).
As a result, the EPA is proposing ASTM D6420-99 (2004) for use in
40 CFR part 63, subpart HHH. The EPA also proposes to allow Method 18
as an option in addition to ASTM D6420-99 (2004). This would allow the
continued use of gas chromatography configurations other than gas
chromatography/mass spectrometry.
The EPA welcomes comments on this aspect of the proposed rulemaking
and, specifically, invites the public to identify potentially-
applicable VCS and to explain why such standards should be used in this
regulation.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
Federal executive policy on EJ. Its main provision directs Federal
agencies, to the greatest extent practicable and permitted by law, to
make EJ part of their mission by identifying and addressing, as
appropriate, disproportionately high and adverse human health or
environmental effects of their programs, policies and activities on
minority populations and low-income populations in the United States.
The EPA has determined that this proposed rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it increases the
level of environmental protection for all affected populations without
having any disproportionately high and adverse human health or
environmental effects on any population, including any minority or low-
income population.
To examine the potential for any EJ issues that might be associated
with each source category, we evaluated the distributions of HAP-
related cancer and noncancer risks across different social, demographic
and economic groups within the populations living near the facilities
where these source categories
[[Page 52798]]
are located. The methods used to conduct demographic analyses for this
rule are described in section VII.C of the preamble for this rule. The
development of demographic analyses to inform the consideration of EJ
issues in EPA rulemakings is an evolving science. The EPA offers the
demographic analyses in this proposed rulemaking as examples of how
such analyses might be developed to inform such consideration, and
invites public comment on the approaches used and the interpretations
made from the results, with the hope that this will support the
refinement and improve utility of such analyses for future rulemakings.
For the demographic analyses, we focused on the populations within
50 km of any facility estimated to have exposures to HAP which result
in cancer risks of 1-in-1 million or greater, or noncancer HI of 1 or
greater (based on the emissions of the source category or the facility,
respectively). We examined the distributions of those risks across
various demographic groups, comparing the percentages of particular
demographic groups to the total number of people in those demographic
groups nationwide. The results, including other risk metrics, such as
average risks for the exposed populations, are documented in source
category-specific technical reports in the docket for both source
categories covered in this proposal.
As described in the preamble, our risk assessments demonstrate that
the regulations for the oil and natural gas production and natural gas
transmission and storage source categories, are associated with an
acceptable level of risk and that the proposed additional requirements
will provide an ample margin of safety to protect public health. Our
analyses also show that, for these source categories, there is no
potential for an adverse environmental effect or human health multi-
pathway effects, and that acute and chronic noncancer health impacts
are unlikely. The EPA has determined that, although there may be an
existing disparity in HAP risks from these sources between some
demographic groups, no demographic group is exposed to an unacceptable
level of risk.
List of Subjects
40 CFR Part 60
Environmental protection, Air pollution control, Reporting and
recordkeeping requirements, Volatile organic compounds.
40 CFR Part 63
Environmental protection, Air pollution control, Reporting and
recordkeeping requirements, Volatile organic compounds.
Dated: July 28, 2011.
Lisa P. Jackson,
Administrator.
For the reasons set out in the preamble, title 40, chapter I of the
Code of Federal Regulations is proposed to be amended as follows:
PART 60--[AMENDED]
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
2. Section 60.17 is amended by:
a. Revising paragraph (a)(7); and
b. Revising paragraphs (a)(91) and (a)(92) to read as follows:
Sec. 60.17 Incorporations by reference.
* * * * *
(a) * * *
(7) ASTM D86-78, 82, 90, 93, 95, 96, Distillation of Petroleum
Products, IBR approved for Sec. Sec. 60.562-2(d), 60.593(d),
60.593a(d), 60.633(h) and 60.5401(h).
* * * * *
(91) ASTM E169-63, 77, 93, General Techniques of Ultraviolet
Quantitative Analysis, IBR approved for Sec. Sec. 60.485a(d)(1),
60.593(b)(2), 60.593a(b)(2), 60.632(f) and 60.5400(f).
(92) ASTM E260-73, 91, 96, General Gas Chromatography Procedures,
IBR approved for Sec. Sec. 60.485a(d)(1), 60.593(b)(2), 60.593a(b)(2),
60.632(f), 60.5400(f) and 60.5406(b).
* * * * *
Subpart KKK--Standards of Performance for Equipment Leaks of VOC
From Onshore Natural Gas Processing Plants for Which Construction,
Reconstruction, or Modification Commenced After January 20, 1984,
and on or Before August 23, 2011
3. The heading for Subpart KKK is revised to read as set out above.
4. Section 60.630 is amended by revising paragraph (b) to read as
follows:
Sec. 60.630 Applicability and designation of affected facility.
* * * * *
(b) Any affected facility under paragraph (a) of this section that
commences construction, reconstruction, or modification after January
20, 1984, and on or before August 23, 2011, is subject to the
requirements of this subpart.
* * * * *
Subpart LLL--Standards of Performance for SO2 Emissions From
Onshore Natural Gas Processing for Which Construction,
Reconstruction, or Modification Commenced After January 20, 1984,
and on or Before August 23, 2011
5. The heading for Subpart LLL is revised to read as set out above.
6. Section 60.640 is amended by revising paragraph (d) to read as
follows:
Sec. 60.640 Applicability and designation of affected facilities.
* * * * *
(d) The provisions of this subpart apply to each affected facility
identified in paragraph (a) of this section which commences
construction or modification after January 20, 1984, and on or before
August 23, 2011.
* * * * *
7. Add subpart OOOO to part 60 to read as follows:
Subpart OOOO--Standards of Performance for Crude Oil and Natural Gas
Production, Transmission, and Distribution
Sec.
60.5360 What is the purpose of this subpart?
60.5365 Am I subject to this subpart?
60.5370 When must I comply with this subpart?
60.5375 What standards apply to gas wellhead affected facilities?
60.5380 What standards apply to centrifugal compressor affected
facilities?
60.5385 What standards apply to reciprocating compressor affected
facilities?
60.5390 What standards apply to pneumatic controller affected
facilities?
60.5395 What standards apply to storage vessel affected facilities?
60.5400 What VOC standards apply to affected facilities at an
onshore natural gas processing plant?
60.5401 What are the exceptions to the VOC standards for affected
facilities at onshore natural gas processing plants?
60.5402 What are the alternative emission limitations for equipment
leaks from onshore natural gas processing plants?
60.5405 What standards apply to sweetening units at onshore natural
gas processing plants?
60.5406 What test methods and procedures must I use for my
sweetening units affected facilities at onshore natural gas
processing plants?
60.5407 What are the requirements for monitoring of emissions and
operations from my sweetening unit affected facilities at onshore
natural gas processing plants?
60.5408 What is an optional procedure for measuring hydrogen sulfide
in acid gas--Tutwiler Procedure?
60.5410 How do I demonstrate initial compliance with the standards
for my
[[Page 52799]]
gas wellhead affected facility, my centrifugal compressor affected
facility, my reciprocating compressor affected facility, my
pneumatic controller affected facility, my storage vessel affected
facility, and my affected facilities at onshore natural gas
processing plants?
60.5415 How do I demonstrate continuous compliance with the
standards for my gas wellhead affected facility, my centrifugal
compressor affected facility, my stationary reciprocating compressor
affected facility, my pneumatic controller affected facility, my
storage vessel affected facility, and my affected facilities at
onshore natural gas processing plants?
60.5420 What are my notification, reporting, and recordkeeping
requirements?
60.5421 What are my additional recordkeeping requirements for my
affected facility subject to VOC requirements for onshore natural
gas processing plants?
60.5422 What are my additional reporting requirements for my
affected facility subject to VOC requirements for onshore natural
gas processing plants?
60.5423 What additional recordkeeping and reporting requirements
apply to my sweetening unit affected facilities at onshore natural
gas processing plants?
60.5425 What part of the General Provisions apply to me?
60.5430 What definitions apply to this subpart?
Table 1 to Subpart OOOO of Part 60--Required Minimum Initial
SO2 Emission Reduction Efficiency (Zi)
Table 2 to Subpart OOOO of Part 60--Required Minimum SO2
Emission Reduction Efficiency (Zc)
Table 3 to Subpart OOOO of Part 60--Applicability of General
Provisions to Subpart OOOO
Subpart OOOO--Standards of Performance for Crude Oil and Natural
Gas Production, Transmission, and Distribution
Sec. 60.5360 What is the purpose of this subpart?
This subpart establishes emission standards and compliance
schedules for the control of volatile organic compounds (VOC) and
sulfur dioxide (SO2) emissions from affected facilities that
commenced construction, modification or reconstruction after August 23,
2011.
Sec. 60.5365 Am I subject to this subpart?
If you are the owner or operator of one or more of the affected
facilities listed in paragraphs (a) through (g) of this section that
commenced construction, modification, or reconstruction after August
23, 2011 your affected facility is subject to the applicable provisions
of this subpart. For the purposes of this subpart, a well completion
operation following hydraulic fracturing or refracturing that occurs at
a gas wellhead facility that commenced construction, modification, or
reconstruction on or before August 23, 2011 is considered a
modification of the gas wellhead facility, but does not affect other
equipment, process units, storage vessels, or pneumatic devices located
at the well site.
(a) A gas wellhead affected facility, is a single natural gas well.
(b) A centrifugal compressor affected facility, which is defined as
a single centrifugal compressor located between the wellhead and the
city gate (as defined in Sec. 60.5430), except that a centrifugal
compressor located at a well site (as defined in Sec. 60.5430) is not
an affected facility under this subpart. For the purposes of this
subpart, your centrifugal compressor is considered to have commenced
construction on the date the compressor is installed at the facility.
(c) A reciprocating compressor affected facility, which is defined
as a single reciprocating compressor located between the wellhead and
the city gate (as defined in Sec. 60.5430), except that a
reciprocating compressor located at a well site (as defined in Sec.
60.5430) is not an affected facility under this subpart. For the
purposes of this subpart, your reciprocating compressor is considered
to have commenced construction on the date the compressor is installed
at the facility.
(d) A pneumatic controller affected facility, which is defined as a
single pneumatic controller.
(e) A storage vessel affected facility, which is defined as a
single storage vessel.
(f) Compressors and equipment (as defined in Sec. 60.5430) located
at onshore natural gas processing plants.
(1) Each compressor in VOC service or in wet gas service is an
affected facility.
(2) The group of all equipment, except compressors, within a
process unit is an affected facility.
(3) Addition or replacement of equipment, as defined in Sec.
60.5430, for the purpose of process improvement that is accomplished
without a capital expenditure shall not by itself be considered a
modification under this subpart.
(4) Equipment (as defined in Sec. 60.5430) associated with a
compressor station, dehydration unit, sweetening unit, underground
storage tank, field gas gathering system, or liquefied natural gas unit
is covered by Sec. Sec. 60.5400, 60.5401, 60.5402, 60.5421 and 60.5422
of this subpart if it is located at an onshore natural gas processing
plant. Equipment (as defined in Sec. 60.5430) not located at the
onshore natural gas processing plant site is exempt from the provisions
of Sec. Sec. 60.5400, 60.5401, 60.5402, 60.5421 and 60.5422 of this
subpart.
(5) Affected facilities located at onshore natural gas processing
plants and described in paragraphs (f)(1) and (f)(2) of this section
are exempt from this subpart if they are subject to and controlled
according to subparts VVa, GGG or GGGa of this part.
(g) Sweetening units located onshore that process natural gas
produced from either onshore or offshore wells.
(1) Each sweetening unit that processes natural gas is an affected
facility; and
(2) Each sweetening unit that processes natural gas followed by a
sulfur recovery unit is an affected facility.
(3) Facilities that have a design capacity less than 2 long tons
per day (LT/D) of hydrogen sulfide (H2S) in the acid gas
(expressed as sulfur) are required to comply with recordkeeping and
reporting requirements specified in Sec. 60.5423(c) but are not
required to comply with Sec. Sec. 60.5405 through 60.5407 and
paragraphs 60.5410(g) and 60.5415(g) of this subpart.
(4) Sweetening facilities producing acid gas that is completely
reinjected into oil-or-gas-bearing geologic strata or that is otherwise
not released to the atmosphere are not subject to Sec. Sec. 60.5405
through 60.5407, and Sec. Sec. 60.5410(g), 60.5415(g), and Sec.
60.5423 of this subpart.
Sec. 60.5370 When must I comply with this subpart?
(a) You must be in compliance with the standards of this subpart no
later than the date of publication of the final rule in the Federal
Register or upon startup, whichever is later.
(b) The provisions for exemption from compliance during periods of
startup, shutdown, and malfunctions provided for in 40 CFR 60.8(c) do
not apply to this subpart.
(c) You are exempt from the obligation to obtain a permit under 40
CFR part 70 or 40 CFR part 71, provided you are not otherwise required
by law to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a).
Notwithstanding the previous sentence, you must continue to comply with
the provisions of this subpart.
Sec. 60.5375 What standards apply to gas wellhead affected
facilities?
If you are the owner or operator of a gas wellhead affected
facility, you must comply with paragraphs (a) through (g) of this
section.
[[Page 52800]]
(a) Except as provided in paragraph (f) of this section, for each
well completion operation with hydraulic fracturing, as defined in
Sec. 60.5430, you must control emissions by the operational procedures
found in paragraphs (a)(1) through (a)(3) of this section.
(1) You must minimize the emissions associated with venting of
hydrocarbon fluids and gas over the duration of flowback by routing the
recovered liquids into storage vessels and routing the recovered gas
into a gas gathering line or collection system.
(2) You must employ sand traps, surge vessels, separators, and
tanks during flowback and cleanout operations to safely maximize
resource recovery and minimize releases to the environment. All salable
quality gas must be routed to the gas gathering line as soon as
practicable.
(3) You must capture and direct flowback emissions that cannot be
directed to the gathering line to a completion combustion device,
except in conditions that may result in a fire hazard or explosion.
Completion combustion devices must be equipped with a reliable
continuous ignition source over the duration of flowback.
(b) You must maintain a log for each well completion operation at
each gas wellhead affected facility. The log must be completed on a
daily basis and must contain the records specified in Sec.
60.5420(c)(1)(iii).
(c) You must demonstrate initial compliance with the standards that
apply to gas wellhead affected facilities as required by Sec. 60.5410.
(d) You must demonstrate continuous compliance with the standards
that apply to gas wellhead affected facilities as required by Sec.
60.5415.
(e) You must perform the required notification, recordkeeping, and
reporting as required by Sec. 60.5420.
(f) For wells meeting the criteria for wildcat or delineation
wells, each well completion operation with hydraulic fracturing at a
gas wellhead affected facility must reduce emissions by using a
completion combustion device meeting the requirements of paragraph
(a)(3) of this section. You must also maintain records specified in
Sec. 60.5420(c)(1)(iii) for wildcat or delineation wells.
Sec. 60.5380 What standards apply to centrifugal compressor affected
facilities?
You must comply with the standards in paragraphs (a) through (d) of
this section, as applicable for each centrifugal compressor affected
facility.
(a) You must equip each rotating compressor shaft with a dry seal
system upon initial startup.
(b) You must demonstrate initial compliance with the standards that
apply to centrifugal compressor affected facilities as required by
Sec. 60.5410.
(c) You must demonstrate continuous compliance with the standards
that apply to centrifugal compressor affected facilities as required by
Sec. 60.5415.
(d) You must perform the required notification, recordkeeping, and
reporting as required by Sec. 60.5420.
Sec. 60.5385 What standards apply to reciprocating compressor
affected facilities?
You must comply with the standards in paragraphs (a) through (d) of
this section for each reciprocating compressor affected facility.
(a) You must replace the reciprocating compressor rod packing
before the compressor has operated for 26,000 hours. The number of
hours of operation must be continuously monitored beginning upon
initial startup of your reciprocating compressor affected facility, or
the date of publication of the final rule in the Federal Register, or
the date of the previous reciprocating compressor rod packing
replacement, whichever is later.
(b) You must demonstrate initial compliance with standards that
apply to reciprocating compressor affected facilities as required by
Sec. 60.5410.
(c) You must demonstrate continuous compliance with standards that
apply to reciprocating compressor affected facilities as required by
Sec. 60.5415.
(d) You must perform the required notification, recordkeeping, and
reporting as required by Sec. 60.5420.
Sec. 60.5390 What standards apply to pneumatic controller affected
facilities?
For each pneumatic controller affected facility you must comply
with the VOC standards, based on natural gas as a surrogate for VOC, in
either paragraph (b) or (c) of this section, as applicable. Pneumatic
controllers meeting the conditions in paragraph (a) are exempt from
this requirement.
(a) The requirements of paragraph (b) or (c) of this section are
not required if you demonstrate, to the Administrator's satisfaction,
that the use of a high bleed device is predicated. The demonstration
may include, but is not limited to, response time, safety and
actuation.
(b) Each pneumatic controller affected facility located at a
natural gas processing plant (as defined in Sec. 60.5430) must have
zero emissions of natural gas.
(c) Each pneumatic controller affected facility not located at a
natural gas processing plant (as defined in Sec. 60.5430) must have
natural gas emissions no greater than 6 standard cubic feet per hour.
(d) You must demonstrate initial compliance with standards that
apply to pneumatic controller affected facilities as required by Sec.
60.5410.
(e) You must demonstrate continuous compliance with standards that
apply to pneumatic controller affected facilities as required by Sec.
60.5415.
(f) You must perform the required notification, recordkeeping, and
reporting as required by Sec. 60.5420, except that you are not
required to submit the notifications specified in Sec. 60.5420(a).
Sec. 60.5395 What standards apply to storage vessel affected
facilities?
You must comply with the standards in paragraphs (a) through (e) of
this section for each storage vessel affected facility.
(a) You must comply with the standards for storage vessels
specified in Sec. 63.766(b) and (c) of this chapter, except as
specified in paragraph (b) of this section. Storage vessels that meet
either one or both of the throughput conditions specified in paragraphs
(a)(1) or (a)(2) of this section are not subject to the standards of
this section.
(1) The annual average condensate throughput is less than 1 barrel
per day per storage vessel.
(2) The annual average crude oil throughput is less than 20 barrels
per day per storage vessel.
(b) This standard does not apply to storage vessels already subject
to and controlled in accordance with the requirements for storage
vessels in Sec. 63.766(b)(1) or (2) of this chapter.
(c) You must demonstrate initial compliance with standards that
apply to storage vessel affected facilities as required by Sec.
60.5410.
(d) You must demonstrate continuous compliance with standards that
apply to storage vessel affected facilities as required by Sec.
60.5415.
(e) You must perform the required notification, recordkeeping, and
reporting as required by Sec. 60.5420.
Sec. 60.5400 What VOC standards apply to affected facilities at an
onshore natural gas processing plant?
This section applies to each compressor in VOC service or in wet
gas service and the group of all equipment (as defined in Sec.
60.5430), except compressors, within a process unit.
(a) You must comply with the requirements of Sec. 60.482-1a(a),
(b), and (d), Sec. 60.482-2a, and Sec. 60.482-4a through 60.482-11a,
except as provided in Sec. 60.5401.
[[Page 52801]]
(b) You may elect to comply with the requirements of Sec. Sec.
60.483-1a and 60.483-2a, as an alternative.
(c) You may apply to the Administrator for permission to use an
alternative means of emission limitation that achieves a reduction in
emissions of VOC at least equivalent to that achieved by the controls
required in this subpart according to the requirements of Sec. 60.5402
of this subpart.
(d) You must comply with the provisions of Sec. 60.485a of this
part except as provided in paragraph (f) of this section.
(e) You must comply with the provisions of Sec. Sec. 60.486a and
60.487a of this part except as provided in Sec. Sec. 60.5401, 60.5421,
and 60.5422 of this part.
(f) You must use the following provision instead of Sec.
60.485a(d)(1): Each piece of equipment is presumed to be in VOC service
or in wet gas service unless an owner or operator demonstrates that the
piece of equipment is not in VOC service or in wet gas service. For a
piece of equipment to be considered not in VOC service, it must be
determined that the VOC content can be reasonably expected never to
exceed 10.0 percent by weight. For a piece of equipment to be
considered in wet gas service, it must be determined that it contains
or contacts the field gas before the extraction step in the process.
For purposes of determining the percent VOC content of the process
fluid that is contained in or contacts a piece of equipment, procedures
that conform to the methods described in ASTM E169-63, 77, or 93, E168-
67, 77, or 92, or E260-73, 91, or 96 (incorporated by reference as
specified in Sec. 60.17) must be used.
Sec. 60.5401 What are the exceptions to the VOC standards for
affected facilities at onshore natural gas processing plants?
(a) You may comply with the following exceptions to the provisions
of subpart VVa of this part.
(b)(1) Each pressure relief device in gas/vapor service may be
monitored quarterly and within 5 days after each pressure release to
detect leaks by the methods specified in Sec. 60.485a(b) except as
provided in Sec. 60.5400(c) and in paragraph (b)(4) of this section,
and Sec. 60.482-4a(a) through (c) of subpart VVa.
(2) If an instrument reading of 5000 ppm or greater is measured, a
leak is detected.
(3)(i) When a leak is detected, it must be repaired as soon as
practicable, but no later than 15 calendar days after it is detected,
except as provided in Sec. 60.482-9a.
(ii) A first attempt at repair must be made no later than 5
calendar days after each leak is detected.
(4)(i) Any pressure relief device that is located in a
nonfractionating plant that is monitored only by non-plant personnel
may be monitored after a pressure release the next time the monitoring
personnel are on-site, instead of within 5 days as specified in
paragraph (b)(1) of this section and Sec. 60.482-4a(b)(1) of subpart
VVa.
(ii) No pressure relief device described in paragraph (b)(4)(i) of
this section must be allowed to operate for more than 30 days after a
pressure release without monitoring.
(c) Sampling connection systems are exempt from the requirements of
Sec. 60.482-5a.
(d) Pumps in light liquid service, valves in gas/vapor and light
liquid service, and pressure relief devices in gas/vapor service that
are located at a nonfractionating plant with a design capacity to
process 283,200 standard cubic meters per day (scmd) (10 million
standard cubic feet per day) or more of field gas are exempt from the
routine monitoring requirements of Sec. Sec. 60.482-2a(a)(1) and
60.482-7a(a), and paragraph (b)(1) of this section.
(e) 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 in the Alaskan North Slope are exempt
from the routine monitoring requirements of Sec. Sec. 60.482-2a(a)(1),
60.482-7a(a), and paragraph (b)(1) of this section.
(f) Flares used to comply with this subpart must comply with the
requirements of Sec. 60.18.
(g) An owner or operator may use the following provisions instead
of Sec. 60.485a(e):
(1) Equipment is in heavy liquid service if the weight percent
evaporated is 10 percent or less at 150 [deg]C (302 [deg]F) as
determined by ASTM Method D86-78, 82, 90, 95, or 96 (incorporated by
reference as specified in Sec. 60.17).
(2) Equipment is in light liquid service if the weight percent
evaporated is greater than 10 percent at 150 [deg]C (302 [deg]F) as
determined by ASTM Method D86-78, 82, 90, 95, or 96 (incorporated by
reference as specified in Sec. 60.17).
Sec. 60.5402 What are the alternative emission limitations for
equipment leaks from onshore natural gas processing plants?
(a) If, in the Administrator's judgment, an alternative means of
emission limitation will achieve a reduction in VOC emissions at least
equivalent to the reduction in VOC emissions achieved under any design,
equipment, work practice or operational standard, the Administrator
will publish, in the Federal Register, a notice permitting the use of
that alternative means for the purpose of compliance with that
standard. The notice may condition permission on requirements related
to the operation and maintenance of the alternative means.
(b) Any notice under paragraph (a) of this section must be
published only after notice and an opportunity for a public hearing.
(c) The Administrator will consider applications under this section
from either owners or operators of affected facilities, or
manufacturers of control equipment.
(d) The Administrator will treat applications under this section
according to the following criteria, except in cases where the
Administrator concludes that other criteria are appropriate:
(1) The applicant must collect, verify and submit test data,
covering a period of at least 12 months, necessary to support the
finding in paragraph (a) of this section.
(2) If the applicant is an owner or operator of an affected
facility, the applicant must commit in writing to operate and maintain
the alternative means so as to achieve a reduction in VOC emissions at
least equivalent to the reduction in VOC emissions achieved under the
design, equipment, work practice or operational standard.
Sec. 60.5405 What standards apply to sweetening units at onshore
natural gas processing plants?
(a) During the initial performance test required by Sec. 60.8(b),
you must achieve at a minimum, an SO2 emission reduction
efficiency (Zi) to be determined from Table 1 of this
subpart based on the sulfur feed rate (X) and the sulfur content of the
acid gas (Y) of the affected facility.
(b) After demonstrating compliance with the provisions of paragraph
(a) of this section, you must achieve at a minimum, an SO2
emission reduction efficiency (Zc) to be determined from
Table 2 of this subpart based on the sulfur feed rate (X) and the
sulfur content of the acid gas (Y) of the affected facility.
60.5406 What test methods and procedures must I use for my sweetening
units affected facilities at onshore natural gas processing plants?
(a) In conducting the performance tests required in Sec. 60.8, you
must use
[[Page 52802]]
the test methods in Appendix A of this part or other methods and
procedures as specified in this section, except as provided in
paragraph Sec. 60.8(b).
(b) During a performance test required by Sec. 60.8, you must
determine the minimum required reduction efficiencies (Z) of
SO2 emissions as required in Sec. 60.5405(a) and (b) as
follows:
(1) The average sulfur feed rate (X) must be computed as follows:
X - KQa[gamma]
Where:
X = average sulfur feed rate, Mg/D (LT/D).
Qa = average volumetric flow rate of acid gas from
sweetening unit, dscm/day (dscf/day).
Y = average H2S concentration in acid gas feed from
sweetening unit, percent by volume, expressed as a decimal.
K = (32 kg S/kg-mole) / ((24.04 dscm/kg-mole) (1000 kg S/Mg))
= 1.331 x 10-3 Mg/dscm, for metric units
= (32 lb S/lb-mole) / ((385.36 dscf/lb-mole) (2240 lb S/long
ton))
= 3.707 x 10-5 long ton/dscf, for English units.
(2) You must use the continuous readings from the process flowmeter
to determine the average volumetric flow rate (Qa) in dscm/
day (dscf/day) of the acid gas from the sweetening unit for each run.
(3) You must use the Tutwiler procedure in Sec. 60.5408 or a
chromatographic procedure following ASTM E-260 (incorporated by
reference--see Sec. 60.17) to determine the H2S
concentration in the acid gas feed from the sweetening unit (Y). At
least one sample per hour (at equally spaced intervals) must be taken
during each 4-hour run. The arithmetic mean of all samples must be the
average H2S concentration (Y) on a dry basis for the run. By
multiplying the result from the Tutwiler procedure by 1.62 x
10-3, the units gr/100 scf are converted to volume percent.
(4) Using the information from paragraphs (b)(1) and (b)(3) of this
section, Tables 1 and 2 of this subpart must be used to determine the
required initial (Zi) and continuous (Zc)
reduction efficiencies of SO2 emissions.
(c) You must determine compliance with the SO2 standards
in Sec. 60.5405(a) or (b) as follows:
(1) You must compute the emission reduction efficiency (R) achieved
by the sulfur recovery technology for each run using the following
equation:
[GRAPHIC] [TIFF OMITTED] TP23AU11.005
(2) You must use the level indicators or manual soundings to
measure the liquid sulfur accumulation rate in the product storage
tanks. You must use readings taken at the beginning and end of each
run, the tank geometry, sulfur density at the storage temperature, and
sample duration to determine the sulfur production rate (S) in kg/hr
(lb/hr) for each run.
(3) You must compute the emission rate of sulfur for each run as
follows:
[GRAPHIC] [TIFF OMITTED] TP23AU11.006
Where:
E = emission rate of sulfur per run, kg/hr.
Ce = concentration of sulfur equivalent (SO2 +
reduced sulfur), g/dscm (lb/dscf).
Qsd = volumetric flow rate of effluent gas, dscm/hr
(dscf/hr).
K1 = conversion factor, 1000 g/kg (7000 gr/lb).
(4) The concentration (Ce) of sulfur equivalent must be
the sum of the SO2 and TRS concentrations, after being
converted to sulfur equivalents. For each run and each of the test
methods specified in this paragraph (c) of this section, you must use a
sampling time of at least 4 hours. You must use Method 1 of Appendix A
to part 60 of this chapter to select the sampling site. The sampling
point in the duct must be at the centroid of the cross-section if the
area is less than 5 m\2\ (54 ft\2\) or at a point no closer to the
walls than 1 m (39 in) if the cross-sectional area is 5 m\2\ or more,
and the centroid is more than 1 m (39 in.) from the wall.
(i) You must use Method 6 of Appendix A to part 60 of this chapter
to determine the SO2 concentration. You must take eight
samples of 20 minutes each at 30-minute intervals. The arithmetic
average must be the concentration for the run. The concentration must
be multiplied by 0.5 x 10-3 to convert the results to sulfur
equivalent.
(ii) You must use Method 15 of appendix A to part 60 of this
chapter to determine the TRS concentration from reduction-type devices
or where the oxygen content of the effluent gas is less than 1.0
percent by volume. The sampling rate must be at least 3 liters/min (0.1
ft\3\/min) to insure minimum residence time in the sample line. You
must take sixteen samples at 15-minute intervals. The arithmetic
average of all the samples must be the concentration for the run. The
concentration in ppm reduced sulfur as sulfur must be multiplied by
1.333 x 10-3 to convert the results to sulfur equivalent.
(iii) You must use Method 16A or Method 15 of appendix A to part 60
of this chapter to determine the reduced sulfur concentration from
oxidation-type devices or where the oxygen content of the effluent gas
is greater than 1.0 percent by volume. You must take eight samples of
20 minutes each at 30-minute intervals. The arithmetic average must be
the concentration for the run. The concentration in ppm reduced sulfur
as sulfur must be multiplied by 1.333 x 10-3 to convert the
results to sulfur equivalent.
(iv) You must use Method 2 of appendix A to part 60 of this chapter
to determine the volumetric flow rate of the effluent gas. A velocity
traverse must be conducted at the beginning and end of each run. The
arithmetic average of the two measurements must be used to calculate
the volumetric flow rate (Qsd) for the run. For the
determination of the effluent gas molecular weight, a single integrated
sample over the 4-hour period may be taken and analyzed or grab samples
at 1-hour intervals may be taken, analyzed, and averaged. For the
moisture content, you must take two samples of at least 0.10 dscm (3.5
dscf) and 10 minutes at the beginning of the 4-hour run and near the
end of the time period. The arithmetic average of the two runs must be
the moisture content for the run.
Sec. 60.5407 What are the requirements for monitoring of emissions
and operations from my sweetening unit affected facilities at onshore
natural gas processing plants?
(a) If your sweetening unit affected facility is located at an
onshore natural gas processing plant and is subject to the provisions
of Sec. 60.5405(a) or (b) you must install, calibrate, maintain, and
operate monitoring devices or perform measurements to determine the
following operations information on a daily basis:
(1) The accumulation of sulfur product over each 24-hour period.
The monitoring method may incorporate the use of an instrument to
measure and record the liquid sulfur production rate, or may be a
procedure for measuring and recording the sulfur liquid levels in the
storage tanks with a level indicator or by manual soundings, with
subsequent calculation of the sulfur production rate based on the tank
geometry, stored sulfur density, and elapsed time between readings. The
method must be designed to be accurate within 2 percent of
the 24-hour sulfur accumulation.
(2) The H2S concentration in the acid gas from the sweetening unit
for each 24-hour period. At least one sample per 24-hour period must be
collected and analyzed using the equation specified in Sec.
60.5406(b)(1). The Administrator may require you to demonstrate that
the H2S concentration obtained from one or more samples over
a 24-hour period is
[[Page 52803]]
within 20 percent of the average of 12 samples collected
at equally spaced intervals during the 24-hour period. In instances
where the H2S concentration of a single sample is not within
20 percent of the average of the 12 equally spaced
samples, the Administrator may require a more frequent sampling
schedule.
(3) The average acid gas flow rate from the sweetening unit. You
must install and operate a monitoring device to continuously measure
the flow rate of acid gas. The monitoring device reading must be
recorded at least once per hour during each 24-hour period. The average
acid gas flow rate must be computed from the individual readings.
(4) The sulfur feed rate (X). For each 24-hour period, you must
compute X using the equation specified in Sec. 60.5406(b)(3).
(5) The required sulfur dioxide emission reduction efficiency for
the 24-hour period. You must use the sulfur feed rate and the
H2S concentration in the acid gas for the 24-hour period, as
applicable, to determine the required reduction efficiency in
accordance with the provisions of Sec. 60.5405(b).
(b) Where compliance is achieved through the use of an oxidation
control system or a reduction control system followed by a continually
operated incineration device, you must install, calibrate, maintain,
and operate monitoring devices and continuous emission monitors as
follows:
(1) A continuous monitoring system to measure the total sulfur
emission rate (E) of SO2 in the gases discharged to the atmosphere. The
SO2 emission rate must be expressed in terms of equivalent
sulfur mass flow rates (kg/hr (lb/hr)). The span of this monitoring
system must be set so that the equivalent emission limit of Sec.
60.5405(b) will be between 30 percent and 70 percent of the measurement
range of the instrument system.
(2) Except as provided in paragraph (b)(3) of this section: A
monitoring device to measure the temperature of the gas leaving the
combustion zone of the incinerator, if compliance with Sec. 60.5405(a)
is achieved through the use of an oxidation control system or a
reduction control system followed by a continually operated
incineration device. The monitoring device must be certified by the
manufacturer to be accurate to within 1 percent of the
temperature being measured.
(3) When performance tests are conducted under the provision of
Sec. 60.8 to demonstrate compliance with the standards under Sec.
60.5405, the temperature of the gas leaving the incinerator combustion
zone must be determined using the monitoring device. If the volumetric
ratio of sulfur dioxide to sulfur dioxide plus total reduced sulfur
(expressed as SO2) in the gas leaving the incinerator is
equal to or less than 0.98, then temperature monitoring may be used to
demonstrate that sulfur dioxide emission monitoring is sufficient to
determine total sulfur emissions. At all times during the operation of
the facility, you must maintain the average temperature of the gas
leaving the combustion zone of the incinerator at or above the
appropriate level determined during the most recent performance test to
ensure the sulfur compound oxidation criteria are met. Operation at
lower average temperatures may be considered by the Administrator to be
unacceptable operation and maintenance of the affected facility. You
may request that the minimum incinerator temperature be reestablished
by conducting new performance tests under Sec. 60.8.
(4) Upon promulgation of a performance specification of continuous
monitoring systems for total reduced sulfur compounds at sulfur
recovery plants, you may, as an alternative to paragraph (b)(2) of this
section, install, calibrate, maintain, and operate a continuous
emission monitoring system for total reduced sulfur compounds as
required in paragraph (d) of this section in addition to a sulfur
dioxide emission monitoring system. The sum of the equivalent sulfur
mass emission rates from the two monitoring systems must be used to
compute the total sulfur emission rate (E).
(c) Where compliance is achieved through the use of a reduction
control system not followed by a continually operated incineration
device, you must install, calibrate, maintain, and operate a continuous
monitoring system to measure the emission rate of reduced sulfur
compounds as SO2 equivalent in the gases discharged to the
atmosphere. The SO2 equivalent compound emission rate must
be expressed in terms of equivalent sulfur mass flow rates (kg/hr (lb/
hr)). The span of this monitoring system must be set so that the
equivalent emission limit of Sec. 60.5405(b) will be between 30 and 70
percent of the measurement range of the system. This requirement
becomes effective upon promulgation of a performance specification for
continuous monitoring systems for total reduced sulfur compounds at
sulfur recovery plants.
(d) For those sources required to comply with paragraph (b) or (c)
of this section, you must calculate the average sulfur emission
reduction efficiency achieved (R) for each 24-hour clock internal. The
24-hour interval may begin and end at any selected clock time, but must
be consistent. You must compute the 24-hour average reduction
efficiency (R) based on the 24-hour average sulfur production rate (S)
and sulfur emission rate (E), using the equation in Sec.
60.5406(c)(1).
(1) You must use data obtained from the sulfur production rate
monitoring device specified in paragraph (a) of this section to
determine S.
(2) You must use data obtained from the sulfur emission rate
monitoring systems specified in paragraphs (b) or (c) of this section
to calculate a 24-hour average for the sulfur emission rate (E). The
monitoring system must provide at least one data point in each
successive 15-minute interval. You must use at least two data points to
calculate each 1-hour average. You must use a minimum of 18 1-hour
averages to compute each 24-hour average.
(e) In lieu of complying with paragraphs (b) or (c) of this
section, those sources with a design capacity of less than 152 Mg/D
(150 LT/D) of H2S expressed as sulfur may calculate the
sulfur emission reduction efficiency achieved for each 24-hour period
by:
[GRAPHIC] [TIFF OMITTED] TP23AU11.000
Where:
R = The sulfur dioxide removal efficiency achieved during the 24-
hour period, percent.
K2 = Conversion factor, 0.02400 Mg/D per kg/hr (0.01071
LT/D per lb/hr).
S = The sulfur production rate during the 24-hour period, kg/hr (lb/
hr).
X = The sulfur feed rate in the acid gas, Mg/D (LT/D).
(f) The monitoring devices required in paragraphs (b)(1), (b)(3)
and (c) of this section must be calibrated at least annually according
to the manufacturer's specifications, as required by Sec. 60.13(b).
(g) The continuous emission monitoring systems required in
paragraphs (b)(1), (b)(3), and (c) of this section must be subject to
the emission monitoring requirements of Sec. 60.13 of the General
Provisions. For conducting the continuous emission monitoring system
performance evaluation required by Sec. 60.13(c), Performance
Specification 2 of appendix B to part 60 of this chapter must apply,
and Method 6 must be used for systems required by paragraph (b) of this
section.
[[Page 52804]]
Sec. 60.5408 What is an optional procedure for measuring hydrogen
sulfide in acid gas--Tutwiler Procedure? \1\
---------------------------------------------------------------------------
\1\ Gas Engineers Handbook, Fuel Gas Engineering practices, The
Industrial Press, 93 Worth Street, New York, NY, 1966, First
Edition, Second Printing, page 6/25 (Docket A-80-20-A, Entry II-I-
67).
---------------------------------------------------------------------------
(a) When an instantaneous sample is desired and H2S
concentration is ten grains per 1000 cubic foot or more, a 100 ml
Tutwiler burette is used. For concentrations less than ten grains, a
500 ml Tutwiler burette and more dilute solutions are used. In
principle, this method consists of titrating hydrogen sulfide in a gas
sample directly with a standard solution of iodine.
(b) Apparatus. (See Figure 1 of this subpart) A 100 or 500 ml
capacity Tutwiler burette, with two-way glass stopcock at bottom and
three-way stopcock at top which connect either with inlet tubulature or
glass-stoppered cylinder, 10 ml capacity, graduated in 0.1 ml
subdivision; rubber tubing connecting burette with leveling bottle.
(c) Reagents. (1) Iodine stock solution, 0.1N. Weight 12.7 g
iodine, and 20 to 25 g cp potassium iodide for each liter of solution.
Dissolve KI in as little water as necessary; dissolve iodine in
concentrated KI solution, make up to proper volume, and store in glass-
stoppered brown glass bottle.
(2) Standard iodine solution, 1 ml = 0.001771 g I. Transfer 33.7 ml
of above 0.1N stock solution into a 250 ml volumetric flask; add water
to mark and mix well. Then, for 100 ml sample of gas, 1 ml of standard
iodine solution is equivalent to 100 grains H2S per cubic
feet of gas.
(3) Starch solution. Rub into a thin paste about one teaspoonful of
wheat starch with a little water; pour into about a pint of boiling
water; stir; let cool and decant off clear solution. Make fresh
solution every few days.
(d) Procedure. Fill leveling bulb with starch solution. Raise (L),
open cock (G), open (F) to (A), and close (F) when solutions starts to
run out of gas inlet. Close (G). Purge gas sampling line and connect
with (A). Lower (L) and open (F) and (G). When liquid level is several
ml past the 100 ml mark, close (G) and (F), and disconnect sampling
tube. Open (G) and bring starch solution to 100 ml mark by raising (L);
then close (G). Open (F) momentarily, to bring gas in burette to
atmospheric pressure, and close (F). Open (G), bring liquid level down
to 10 ml mark by lowering (L). Close (G), clamp rubber tubing near (E)
and disconnect it from burette. Rinse graduated cylinder with a
standard iodine solution (0.00171 g I per ml); fill cylinder and record
reading. Introduce successive small amounts of iodine thru (F); shake
well after each addition; continue until a faint permanent blue color
is obtained. Record reading; subtract from previous reading, and call
difference D.
(e) With every fresh stock of starch solution perform a blank test
as follows: Introduce fresh starch solution into burette up to 100 ml
mark. Close (F) and (G). Lower (L) and open (G). When liquid level
reaches the 10 ml mark, close (G). With air in burette, titrate as
during a test and up to same end point. Call ml of iodine used C. Then,
Grains H2S per 100 cubic foot of gas = 100 (D-C)
(f) Greater sensitivity can be attained if a 500 ml capacity
Tutwiler burette is used with a more dilute (0.001N) iodine solution.
Concentrations less than 1.0 grains per 100 cubic foot can be
determined in this way. Usually, the starch-iodine end point is much
less distinct, and a blank determination of end point, with
H2S-free gas or air, is required.
BILLING CODE 6560-50-P
[[Page 52805]]
[GRAPHIC] [TIFF OMITTED] TP23AU11.001
BILLING CODE 6560-50-C
Sec. 60.5410 How do I demonstrate initial compliance with the
standards for my gas wellhead affected facility, my centrifugal
compressor affected facility, my reciprocating compressor affected
facility, my pneumatic controller affected facility, my storage vessel
affected facility, and my affected facilities at onshore natural gas
processing plants?
You must determine initial compliance with the standards for each
affected facility using the requirements in paragraphs (a) through (g)
of this section. The initial compliance period begins on the date of
publication of the final rule in the Federal Register or upon initial
startup, whichever is later, and ends on the date the first annual
report is due as specified in Sec. 60.5420(b).
(a) You have achieved initial compliance with standards for each
well completion operation conducted at your gas wellhead affected
facility if you have complied with paragraphs (a)(1) and (a)(2) of this
section.
(1) You have notified the Administrator within 30 days of the
commencement of the well completion operation, the date of the
commencement of the well completion operation, the latitude and
longitude coordinates of the well in decimal degrees to an accuracy and
precision of five (5) decimals of a degree using the North American
Datum (NAD) of 1983.
(2) You have maintained a log of records as specified in Sec.
60.5375(b) or (f) for each well completion operation conducted during
the initial compliance period.
[[Page 52806]]
(3) You have submitted the initial annual report for your wellhead
affected facility as required in Sec. 60.5420(b).
(b) You have achieved initial compliance with standards for your
centrifugal compressor affected facility if the centrifugal compressor
is fitted with a dry seal system upon initial startup as required by
Sec. 60.5380.
(c) You have achieved initial compliance with standards for each
reciprocating compressor affected facility if you have complied with
paragraphs (c)(1) and (c)(2) of this section.
(1) During the initial compliance period, you have continuously
monitored the number of hours of operation.
(2) You have included the cumulative number of hours of operation
for your reciprocating compressor affected facility during the initial
compliance period in your initial annual report required in Sec.
60.5420(b).
(d) You have achieved initial compliance with emission standards
for your pneumatic controller affected facility if you comply with the
requirements specified in paragraphs (d)(1) through (d)(4) of this
section.
(1) You have demonstrated, to the Administrator's satisfaction, the
use of a high bleed device is predicated as specified in Sec.
60.5490(a).
(2) You own or operate a pneumatic controller affected facility
located at a natural gas processing plant and your pneumatic controller
is driven other than by use of natural gas and therefore emits zero
natural gas.
(3) You own or operate a pneumatic controller affected facility not
located at a natural gas processing plant and the manufacturer's design
specifications guarantee the controller emits less than or equal to 6.0
standard cubic feet of gas per hour.
(4) You have included the information in paragraphs (d)(1) through
(d)(3) of this section in the initial annual report submitted for your
pneumatic controller affected facilities according to the requirements
of Sec. 60.5420(b).
(e) You have demonstrated initial compliance with emission
standards for your storage vessel affected facility if you are
complying with paragraphs (e)(1) through (e)(7) of this section.
(1) You have equipped the storage vessel with a closed vent system
that meets the requirements of Sec. 63.771(c) of this chapter
connected to a control device that meets the conditions specified in
Sec. 63.771(d).
(2) You have conducted an initial performance test as required in
Sec. 63.772(e) of this chapter within 180 days after initial startup
or the date of publication of the final rule in the Federal Register
and have conducted the compliance demonstration in Sec. 63.772(f).
(3) You have conducted the initial inspections required in Sec.
63.773(c) of this chapter.
(4) You have installed and operated continuous parameter monitoring
systems in accordance with Sec. 63.773(d) of this chapter.
(5) If you are exempt from the standards of Sec. 60.5395 according
to Sec. 60.5395(a)(1) or (a)(2), you have determined the condensate or
crude oil throughput, as applicable, according to paragraphs (e)(5)(i)
or (e)(5)(ii) of this section and demonstrated to the Administrator's
satisfaction that your annual average condensate throughput is less
than 1 barrel per day per tank and your annual average crude oil
throughput is less than 20 barrels per day per tank.
(i) You have installed and operated a flow meter to measure
condensate or crude oil throughput in accordance with the
manufacturer's procedures or specifications.
(ii) You have used any other method approved by the Administrator
to determine annual average condensate or crude oil throughput.
(6) You have submitted the information in paragraphs (e)(1) through
(e)(5) of this section in the initial annual report for your storage
vessel affected facility as required in Sec. 60.5420(b).
(f) For affected facilities at onshore natural gas processing
plants, initial compliance with the VOC requirements is demonstrated if
you are in compliance with the requirements of Sec. 60.5400.
(g) For sweetening unit affected facilities at onshore natural gas
processing plants, initial compliance is demonstrated according to
paragraphs (g)(1) through (g)(3) of this section.
(1) To determine compliance with the standards for SO2
specified in Sec. 60.5405(a), during the initial performance test as
required by Sec. 60.8, the minimum required sulfur dioxide emission
reduction efficiency (Zi) is compared to the emission
reduction efficiency (R) achieved by the sulfur recovery technology as
specified in paragraphs (g)(1)(i) and (g)(1)(ii) of this section.
(i) If R >= Zi, your affected facility is in compliance.
(ii) If R < Zi, your affected facility is not in
compliance.
(2) The emission reduction efficiency (R) achieved by the sulfur
reduction technology must be determined using the procedures in Sec.
60.5406(c)(1).
(3) You have submitted the results of paragraphs (g)(1) and (g)(2)
of this section in the initial annual report submitted for your
sweetening unit affected facilities at onshore natural gas processing
plants.
Sec. 60.5415 How do I demonstrate continuous compliance with the
standards for my gas wellhead affected facility, my centrifugal
compressor affected facility, my stationary reciprocating compressor
affected facility, my pneumatic controller affected facility, my
storage vessel affected facility, and my affected facilities at onshore
natural gas processing plants?
(a) For each gas wellhead affected facility, you must demonstrate
continuous compliance by maintaining the records for each completion
operation (as defined in Sec. 60.5430) specified in Sec. 60.5420.
(b) For each centrifugal compressor affected facility, continuous
compliance is demonstrated if the rotating compressor shaft is equipped
with a dry seal.
(c) For each reciprocating compressor affected facility, you have
demonstrated continuous compliance according to paragraphs (c)(1) and
(2) of this section
(1) You have continuously monitored the number of hours of
operation for each reciprocating compressor affected facility since
initial startup, or the date of publication of the final rule in the
Federal Register, or the date of the previous reciprocating compressor
rod packing replacement, whichever is later. The cumulative number of
hours of operation must be included in the annual report as required in
Sec. 60.5420(b)(4).
(2) You have replaced the reciprocating compressor rod packing
before the total number of hours of operation reaches 26,000 hours.
(d) For each pneumatic controller affected facility, continuous
compliance is demonstrated by maintaining the records demonstrating
that you have installed and operated the pneumatic controllers as
required in Sec. 60.5390(a), (b) or (c).
(e) For each storage vessel affected facility, continuous
compliance is demonstrated according to Sec. 63.772(f) of this
chapter.
(f) For affected facilities at onshore natural gas processing
plants, continuous compliance with VOC requirements is demonstrated if
you are in compliance with the requirements of Sec. 60.5400.
(g) For each sweetening unit affected facility at onshore natural
gas processing plants, you must demonstrate continuous compliance with
the standards for SO2 specified in
[[Page 52807]]
Sec. 60.5405(b) according to paragraphs (g)(1) and (g)(2) of this
section.
(1) The minimum required SO2 emission reduction
efficiency (Zc) is compared to the emission reduction
efficiency (R) achieved by the sulfur recovery technology.
(i) If R >= Zc, your affected facility is in compliance.
(ii) If R < Zc, your affected facility is not in
compliance.
(2) The emission reduction efficiency (R) achieved by the sulfur
reduction technology must be determined using the procedures in Sec.
60.5406(c)(1).
(h) Affirmative defense for exceedance of emission limit during
malfunction. In response to an action to enforce the standards set
forth in Sec. Sec. 60.5375, 60.5380, 60.5385, 60.5390, 60.5395,
60.5400, and 60.5405, you may assert an affirmative defense to a claim
for civil penalties for exceedances of such standards that are caused
by malfunction, as defined at Sec. 60.2. Appropriate penalties may be
assessed, however, if you fail to meet your burden of proving all of
the requirements in the affirmative defense. The affirmative defense
shall not be available for claims for injunctive relief.
(1) To establish the affirmative defense in any action to enforce
such a limit, you must timely meet the notification requirements in
Sec. 60.5420(a), and must prove by a preponderance of evidence that:
(i) The excess emissions:
(A) Were caused by a sudden, infrequent, and unavoidable failure of
air pollution control and monitoring equipment, process equipment, or a
process to operate in a normal or usual manner, and
(B) Could not have been prevented through careful planning, proper
design or better operation and maintenance practices; and
(C) Did not stem from any activity or event that could have been
foreseen and avoided, or planned for; and
(D) Were not part of a recurring pattern indicative of inadequate
design, operation, or maintenance; and
(ii) Repairs were made as expeditiously as possible when the
applicable emission limitations were being exceeded. Off-shift and
overtime labor were used, to the extent practicable to make these
repairs; and
(iii) The frequency, amount and duration of the excess emissions
(including any bypass) were minimized to the maximum extent practicable
during periods of such emissions; and
(iv) If the excess emissions resulted from a bypass of control
equipment or a process, then the bypass was unavoidable to prevent loss
of life, personal injury, or severe property damage; and
(v) All possible steps were taken to minimize the impact of the
excess emissions on ambient air quality, the environment and human
health; and
(vi) All emissions monitoring and control systems were kept in
operation if at all possible, consistent with safety and good air
pollution control practices; and
(vii) All of the actions in response to the excess emissions were
documented by properly signed, contemporaneous operating logs; and
(viii) At all times, the facility was operated in a manner
consistent with good practices for minimizing emissions; and
(ix) A written root cause analysis has been prepared, the purpose
of which is to determine, correct, and eliminate the primary causes of
the malfunction and the excess emissions resulting from the malfunction
event at issue. The analysis shall also specify, using best monitoring
methods and engineering judgment, the amount of excess emissions that
were the result of the malfunction.
(2) The owner or operator of the facility experiencing an
exceedance of its emission limit(s) during a malfunction shall notify
the Administrator by telephone or facsimile (FAX) transmission as soon
as possible, but no later than 2 business days after the initial
occurrence of the malfunction, if it wishes to avail itself of an
affirmative defense to civil penalties for that malfunction. The owner
or operator seeking to assert an affirmative defense shall also submit
a written report to the Administrator within 45 days of the initial
occurrence of the exceedance of the standards in Sec. Sec. 60.5375,
60.5380, 60.5385, 60.5390, 60.5395, and 60.5400 to demonstrate, with
all necessary supporting documentation, that it has met the
requirements set forth in paragraph (a) of this section. The owner or
operator may seek an extension of this deadline for up to 30 additional
days by submitting a written request to the Administrator before the
expiration of the 45-day period. Until a request for an extension has
been approved by the Administrator, the owner or operator is subject to
the requirement to submit such report within 45 days of the initial
occurrence of the exceedance.
Sec. 60.5420 What are my notification, reporting, and recordkeeping
requirements?
(a) You must submit the notifications required in Sec. 60.7(a)(1),
(a)(3) and (a)(4), and according to paragraphs (a)(1) and (a)(2) of
this section, if you own or operate one or more of the affected
facilities specified in Sec. 60.5365. For the purposes of this
subpart, a workover that occurs after August 23, 2011 at each affected
facility for which construction, reconstruction, or modification
commenced on or before August 23, 2011 is considered a modification for
which a notification must be submitted under Sec. 60.7(a)(4).
(1) If you own or operate a pneumatic controller affected facility
you are not required to submit the notifications required in Sec.
60.7(a)(1), (a)(3) and (a)(4).
(2) If you own or operate a gas wellhead affected facility, you
must submit a notification to the Administrator within 30 days of the
commencement of the well completion operation. The notification must
include the date of commencement of the well completion operation, the
latitude and longitude coordinates of the well in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using the North
American Datum of 1983.
(b) Reporting requirements. You must submit annual reports
containing the information specified in paragraphs (b)(1) through
(b)(6) of this section to the Administrator. The initial annual report
is due 1 year after the initial startup date for your affected facility
or 1 year after the date of publication of the final rule in the
Federal Register, whichever is later. Subsequent annual reports are due
on the same date each year as the initial annual report. If you own or
operate more than one affected facility, you may submit one report for
multiple affected facilities provided the report contains all of the
information required as specified in paragraphs (b)(1) through (b)(6)
of this section.
(1) The general information specified in paragraphs (b)(1)(i)
through (b)(1)(iii) of this section.
(i) The company name and address of the affected facility.
(ii) An identification of each affected facility being included in
the annual report.
(iii) Beginning and ending dates of the reporting period.
(2) For each gas wellhead affected facility, the information in
paragraphs (b)(2)(i) through (b)(2)(iii) of this section.
(i) An identification of each well completion operation, as defined
in Sec. 60.5430, for each gas wellhead affected facility conducted
during the reporting period;
(ii) A record of deviations in cases where well completion
operations with hydraulic fracturing were not performed in compliance
with the requirements
[[Page 52808]]
specified in Sec. 60.5375 for each gas well affected facility.
(iii) Records specified in Sec. 60.5375(b) for each well
completion operation that occurred during the reporting period.
(3) For each centrifugal compressor affected facility installed
during the reporting period, documentation that the centrifugal
compressor is equipped with dry seals.
(4) For each reciprocating compressor affected facility, the
information specified in paragraphs (b)(4)(i) and (b)(4)(ii) of this
section.
(i) The cumulative number of hours or operation since initial
startup, the date of publication of the final rule in the Federal
Register, or since the previous reciprocating compressor rod packing
replacement, whichever is later.
(ii) Documentation that the reciprocating compressor rod packing
was replaced before the cumulative number of hours of operation reached
24,000 hours.
(5) For each pneumatic controller affected facility, the
information specified in paragraphs (b)(5)(i) through (b)(5)(iv) of
this section.
(i) The date, location and manufacturer specifications for each
pneumatic controller installed.
(ii) If applicable, documentation that the use of high bleed
pneumatic devices is predicated and the reasons why.
(iii) For pneumatic controllers not installed at a natural gas
processing plant, the manufacturer's guarantee that the device is
designed such that natural gas emissions are less than 6 standard cubic
feet per hour.
(iv) For pneumatic controllers installed at a natural gas
processing plant, documentation that each controllers has zero natural
gas emissions.
(6) For each storage vessel affected facility, the information in
paragraphs (b)(6)(i) and (b)(6)(ii) of this section.
(i) If required to reduce emissions by complying with Sec.
60.5395(a)(1), the records specified in Sec. 63.774(b)(2) through
(b)(8) of this chapter.
(ii) Documentation that the annual average condensate throughput is
less than 1 barrel per day per storage vessel and crude oil throughput
is less than 21 barrels per day per storage for meeting the
requirements in Sec. 60.5395(a)(1) or (a)(2).
(c) Recordkeeping requirements. You must maintain the records
identified as specified in Sec. 60.7(f) and in paragraphs (c)(1)
through (c)(5) of this section
(1) The records for each gas wellhead affected facility as
specified in paragraphs (c)(1)(i) through (c)(1)(iii).
(i) Records identifying each well completion operation for each gas
wellhead affected facility conducted during the reporting period;
(ii) Record of deviations in cases where well completion operations
with hydraulic fracturing were not performed in compliance with the
requirements specified in Sec. 60.5375.
(iii) Records required in Sec. 60.5375(b) or (f) for each well
completion operation conducted for each gas wellhead affected facility
that occurred during the reporting period. You must maintain the
records specified in paragraphs (c)(1)(iii)(A) and (c)(1)(iii)(B) of
this section.
(A) For each gas wellheads affected facility required to comply
with the requirements of Sec. 60.5375(a), you must record: The
location of the well; the duration of flowback; duration of recovery to
the sales line; duration of combustion; duration of venting; and
specific reasons for venting in lieu of capture or combustion. The
duration must be specified in hours of time.
(B) For each gas wellhead affected facility required to comply with
the requirements of Sec. 60.5375(f), you must maintain the records
specified in paragraph (c)(1)(iii)(A) of this section except that you
do not have to record the duration of recovery to the sales line. In
addition, you must record the distance, in miles, of the nearest
gathering line.
(2) For each centrifugal compressor affected facility, you must
maintain records on the type of seal system installed.
(3) For each reciprocating compressors affected facility, you must
maintain the records in paragraphs (c)(3)(i) and (c)(3)(ii) of this
section.
(i) Records of the cumulative number of hours of operation since
initial startup or the date of publication of the final rule in the
Federal Register, or the previous replacement of the reciprocating
compressor rod packing, whichever is later.
(ii) Records of the date and time of each reciprocating compressor
rod packing replacement.
(4) For each pneumatic controller affected facility, you must
maintain the records identified in paragraphs (c)(4)(i) through
(c)(4)(iv) of this section.
(i) Records of the date, location and manufacturer specifications
for each pneumatic controller installed.
(ii) Records of the determination that the use of high bleed
pneumatic devices is predicated and the reasons why.
(iii) If the pneumatic controller affected facility is not located
at a natural gas processing plant, records of the manufacturer's
guarantee that the device is designed such that natural gas emissions
are less than 6 standard cubic feet per hour.
(iv) If the pneumatic controller affected facility is located at a
natural gas processing plant, records of the documentation that only
instrument air controllers are used.
(5) For each storage vessel affected facility, you must maintain
the records identified in paragraphs (c)(5)(i) and (c)(5)(ii) of this
section.
(i) If required to reduce emissions by complying with Sec. 63.766,
the records specified in Sec. 63.774(b)(2) through (8) of this
chapter.
(ii) Records of the determination that the annual average
condensate throughput is less than 1 barrel per day per storage vessel
and crude oil throughput is less than 21 barrels per day per storage
vessel for the exemption under Sec. 60.5395(a)(1) and (a)(2).
Sec. 60.5421 What are my additional recordkeeping requirements for my
affected facility subject to VOC requirements for onshore natural gas
processing plants?
(a) You must comply with the requirements of paragraph (b) of this
section in addition to the requirements of Sec. 60.486a.
(b) The following recordkeeping requirements apply to pressure
relief devices subject to the requirements of Sec. 60.5401(b)(1) of
this subpart.
(1) When each leak is detected as specified in Sec. 60.5401(b)(2),
a weatherproof and readily visible identification, marked with the
equipment identification number, must be attached to the leaking
equipment. The identification on the pressure relief device may be
removed after it has been repaired.
(2) When each leak is detected as specified in Sec. 60.5401(b)(2),
the following information must be recorded in a log and shall be kept
for 2 years in a readily accessible location:
(i) The instrument and operator identification numbers and the
equipment identification number.
(ii) The date the leak was detected and the dates of each attempt
to repair the leak.
(iii) Repair methods applied in each attempt to repair the leak.
(iv) ``Above 500 ppm'' if the maximum instrument reading measured
by the methods specified in paragraph (a) of this section after each
repair attempt is 500 ppm or greater.
(v) ``Repair delayed'' and the reason for the delay if a leak is
not repaired within 15 calendar days after discovery of the leak.
(vi) The signature of the owner or operator (or designate) whose
decision it was that repair could not be effected without a process
shutdown.
[[Page 52809]]
(vii) The expected date of successful repair of the leak if a leak
is not repaired within 15 days.
(viii) Dates of process unit shutdowns that occur while the
equipment is unrepaired.
(ix) The date of successful repair of the leak.
(x) A list of identification numbers for equipment that are
designated for no detectable emissions under the provisions of Sec.
60.482-4a(a). The designation of equipment subject to the provisions of
Sec. 60.482-4a(a) must be signed by the owner or operator.
Sec. 60.5422 What are my additional reporting requirements for my
affected facility subject to VOC requirements for onshore natural gas
processing plants?
(a) You must comply with the requirements of paragraphs (b) and (c)
of this section in addition to the requirements of Sec. 60.487a(a),
(b), (c)(2)(i) through (iv), and (c)(2)(vii) through (viii).
(b) An owner or operator must include the following information in
the initial semiannual report in addition to the information required
in Sec. 60.487a(b)(1) through (4): Number of pressure relief devices
subject to the requirements of Sec. 60.5401(b) except for those
pressure relief devices designated for no detectable emissions under
the provisions of Sec. 60.482-4a(a) and those pressure relief devices
complying with Sec. 60.482-4a(c).
(c) An owner or operator must include the following information in
all semiannual reports in addition to the information required in Sec.
60.487a(c)(2)(i) through (vi):
(1) Number of pressure relief devices for which leaks were detected
as required in Sec. 60.5401(b)(2); and
(2) Number of pressure relief devices for which leaks were not
repaired as required in Sec. 60.5401(b)(3).
Sec. 60.5423 What additional recordkeeping and reporting requirements
apply to my sweetening unit affected facilities at onshore natural gas
processing plants?
(a) You must retain records of the calculations and measurements
required in Sec. 60.5405(a) and (b) and Sec. 60.5407(a) through (g)
for at least 2 years following the date of the measurements. This
requirement is included under Sec. 60.7(d) of the General Provisions.
(b) You must submit a written report of excess emissions to the
Administrator semiannually. For the purpose of these reports, excess
emissions are defined as:
(1) Any 24-hour period (at consistent intervals) during which the
average sulfur emission reduction efficiency (R) is less than the
minimum required efficiency (Z).
(2) For any affected facility electing to comply with the
provisions of Sec. 60.5407(b)(2), any 24-hour period during which the
average temperature of the gases leaving the combustion zone of an
incinerator is less than the appropriate operating temperature as
determined during the most recent performance test in accordance with
the provisions of Sec. 60.5407(b)(2). Each 24-hour period must consist
of at least 96 temperature measurements equally spaced over the 24
hours.
(c) To certify that a facility is exempt from the control
requirements of these standards, for each facility with a design
capacity less that 2 LT/D of H2S in the acid gas (expressed
as sulfur) you must keep, for the life of the facility, an analysis
demonstrating that the facility's design capacity is less than 2 LT/D
of H2S expressed as sulfur.
(d) If you elect to comply with Sec. 60.5407(e) you must keep, for
the life of the facility, a record demonstrating that the facility's
design capacity is less than 150 LT/D of H2S expressed as
sulfur.
(e) The requirements of paragraph (b) of this section remain in
force until and unless the EPA, in delegating enforcement authority to
a state under section 111(c) of the Act, approves reporting
requirements or an alternative means of compliance surveillance adopted
by such state. In that event, affected sources within the state will be
relieved of obligation to comply with paragraph (b) of this section,
provided that they comply with the requirements established by the
state.
Sec. 60.5425 What part of the General Provisions apply to me?
Table 3 to this subpart shows which parts of the General Provisions
in Sec. Sec. 60.1 through 60.19 apply to you.
Sec. 60.5430 What definitions apply to this subpart?
As used in this subpart, all terms not defined herein shall have
the meaning given them in the Act, in subpart A or subpart VVa of part
60; and the following terms shall have the specific meanings given
them.
Acid gas means a gas stream of hydrogen sulfide (H2S)
and carbon dioxide (CO2) that has been separated from sour
natural gas by a sweetening unit.
Alaskan North Slope means the approximately 69,000 square-mile area
extending from the Brooks Range to the Arctic Ocean.
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.
Centrifugal compressor means a piece of equipment that compresses a
process gas by means of mechanical rotating vanes or impellers.
City gate means the delivery point at which natural gas is
transferred from a transmission pipeline to the local gas utility.
Completion combustion device means any ignition device, installed
horizontally or vertically, used in exploration and production
operations to combust otherwise vented emissions from completions or
workovers.
Compressor means a piece of equipment that compresses process gas
and is usually a centrifugal compressor or a reciprocating compressor.
Compressor station means any permanent combination of compressors
that move natural gas at increased pressure from fields, in
transmission pipelines, or into storage.
Condensate means a hydrocarbon liquid separated from natural gas
that condenses due to changes in the temperature, pressure, or both,
and remains liquid at standard conditions, as specified in Sec. 60.2.
For the purposes of this subpart, a hydrocarbon liquid with an API
gravity equal to or greater than 40 degrees is considered condensate.
Crude oil means crude petroleum oil or any other hydrocarbon
liquid, which are produced at the well in liquid form by ordinary
production methods, and which are not the result of condensation of gas
before or after it leaves the reservoir. For the purposes of this
subpart, a hydrocarbon liquid with an API gravity less than 40 degrees
is considered crude oil.
Dehydrator means a device in which an absorbent directly contacts a
natural gas stream and absorbs water in a contact tower or absorption
column (absorber).
Delineation well means a well drilled in order to determine the
boundary of a field or producing reservoir.
Equipment means each pump, pressure relief device, open-ended valve
or line, valve, compressor, and flange or other connector that is in
VOC service or in wet gas service, and any device or system required by
this subpart.
Field gas means feedstock gas entering the natural gas processing
plant.
Field gas gathering means the system used to transport field gas
from a field to the main pipeline in the area.
Flare means a thermal oxidation system using an open (without
enclosure) flame.
Flowback means the process of allowing fluids to flow from the well
following a treatment, either in
[[Page 52810]]
preparation for a subsequent phase of treatment or in preparation for
cleanup and returning the well to production.
Flow line means surface pipe through which oil and/or natural gas
travels from the well.
Gas-driven pneumatic controller means a pneumatic controller
powered by pressurized natural gas.
Gas processing plant process unit means equipment assembled for the
extraction of natural gas liquids from field gas, the fractionation of
the liquids into natural gas products, or other operations associated
with the processing of natural gas products. A process unit can operate
independently if supplied with sufficient feed or raw materials and
sufficient storage facilities for the products.
Gas well means a well, the principal production of which at the
mouth of the well is gas.
High-bleed pneumatic devices means automated, continuous bleed flow
control devices powered by pressurized natural gas and used for
maintaining a process condition such as liquid level, pressure, delta-
pressure and temperature. Part of the gas power stream which is
regulated by the process condition flows to a valve actuator controller
where it vents continuously (bleeds) to the atmosphere at a rate in
excess of six standard cubic feet per hour.
Hydraulic fracturing means the process of directing pressurized
liquids, containing water, proppant, and any added chemicals, to
penetrate tight sand, shale, or coal formations that involve high rate,
extended back flow to expel fracture fluids and sand during completions
and well workovers.
In light liquid service means that the piece of equipment contains
a liquid that meets the conditions specified in Sec. 60.485a(e) or
Sec. 60.5401(h)(2) of this part.
In wet gas service means that a compressor or piece of equipment
contains or contacts the field gas before the extraction step at a gas
processing plant process unit.
Liquefied natural gas unit means a unit used to cool natural gas to
the point at which it is condensed into a liquid which is colorless,
odorless, non-corrosive and non-toxic.
Low-bleed pneumatic controller means automated flow control devices
powered by pressurized natural gas and used for maintaining a process
condition such as liquid level, pressure, delta-pressure and
temperature. Part of the gas power stream which is regulated by the
process condition flows to a valve actuator controller where it vents
continuously (bleeds) to the atmosphere at a rate equal to or less than
six standard cubic feet per hour.
Modification means any physical change in, or change in the method
of operation of, an affected facility which increases the amount of VOC
or natural gas emitted into the atmosphere by that facility or which
results in the emission of VOC or natural gas into the atmosphere not
previously emitted. For the purposes of this subpart, each recompletion
of a fractured or refractured existing gas well is considered to be a
modification.
Natural gas liquids means the hydrocarbons, such as ethane,
propane, butane, and pentane that are extracted from field gas.
Natural gas processing plant (gas plant) means any processing site
engaged in the extraction of natural gas liquids from field gas,
fractionation of mixed natural gas liquids to natural gas products, or
both.
Nonfractionating plant means any gas plant that does not
fractionate mixed natural gas liquids into natural gas products.
Non gas-driven pneumatic device means an instrument that is
actuated using other sources of power than pressurized natural gas;
examples include solar, electric, and instrument air.
Onshore means all facilities except those that are located in the
territorial seas or on the outer continental shelf.
Plunger lift system means an intermittent gas lift that uses gas
pressure buildup in the casing-tubing annulus to push a steel plunger,
and the column of fluid ahead of it, up the well tubing to the surface.
Pneumatic controller means an automated instrument used for
maintaining a process condition such as liquid level, pressure, delta-
pressure and temperature.
Pneumatic pump means a pump that uses pressurized natural gas to
move a piston or diaphragm, which pumps liquids on the opposite side of
the piston or diaphragm.
Process unit means components assembled for the extraction of
natural gas liquids from field gas, the fractionation of the liquids
into natural gas products, or other operations associated with the
processing of natural gas products. A process unit can operate
independently if supplied with sufficient feed or raw materials and
sufficient storage facilities for the products.
Reciprocating compressor means a piece of equipment that increases
the pressure of a process gas by positive displacement, employing
linear movement of the driveshaft.
Reciprocating compressor rod packing means a series of flexible
rings in machined metal cups that fit around the reciprocating
compressor piston rod to create a seal limiting the amount of
compressed natural gas that escapes to the atmosphere.
Reduced emissions completion means a well completion where gas
flowback that is otherwise vented is captured, cleaned, and routed to
the sales line.
Reduced emissions recompletion means a well completion following
refracturing of a gas well where gas flowback that is otherwise vented
is captured, cleaned, and routed to the sales line.
Reduced sulfur compounds means H2S, carbonyl sulfide
(COS), and carbon disulfide (CS2).
Routed to a process or route to a process means the emissions are
conveyed to any enclosed portion of a process unit where the emissions
are predominantly recycled and/or consumed in the same manner as a
material that fulfills the same function in the process and/or
transformed by chemical reaction into materials that are not regulated
materials and/or incorporated into a product; and/or recovered.
Salable quality gas means natural gas that meets the composition,
moisture, or other limits set by the purchaser of the natural gas.
Sales line means pipeline, generally small in diameter, used to
transport oil or gas from the well to a processing facility or a
mainline pipeline.
Storage vessel means a stationary vessel or series of stationary
vessels that are either manifolded together or are located at a single
well site and that have potential for VOC emissions equal to or greater
than 10 tpy.
Sulfur production rate means the rate of liquid sulfur accumulation
from the sulfur recovery unit.
Sulfur recovery unit means a process device that recovers element
sulfur from acid gas.
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.
Sweetening unit means a process device that removes hydrogen
sulfide and/or carbon dioxide from the natural gas stream.
Total Reduced Sulfur (TRS) means the sum of the sulfur compounds
hydrogen sulfide, methyl mercaptan, dimethyl sulfide, and dimethyl
disulfide as measured by Method 16 of appendix A to part 60 of this
chapter.
Total SO2 equivalents means the sum of volumetric or mass
concentrations of
[[Page 52811]]
the sulfur compounds obtained by adding the quantity existing as
SO2 to the quantity of SO2 that would be obtained
if all reduced sulfur compounds were converted to SO2 (ppmv
or kg/dscm (lb/dscf)).
Underground storage tank means a storage tank stored below ground.
Well means an oil or gas well, a hole drilled for the purpose of
producing oil or gas, or a well into which fluids are injected.
Well completion means the process that allows for the flow of
petroleum or natural gas from newly drilled wells to expel drilling and
reservoir fluids and tests the reservoir flow characteristics, steps
which may vent produced gas to the atmosphere via an open pit or tank.
Well completion also involves connecting the well bore to the
reservoir, which may include treating the formation or installing
tubing, packer(s), or lifting equipment.
Well completion operation means any well completion or well
workover occurring at a gas wellhead affected facility.
Well site means the areas that are directly disturbed during the
drilling and subsequent operation of, or affected by, production
facilities directly associated with any oil well, gas well, or
injection well and its associated well pad.
Wellhead means the piping, casing, tubing and connected valves
protruding above the earth's surface for an oil and/or natural gas
well. The wellhead ends where the flow line connects to a wellhead
valve. The wellhead does not include other equipment at the well site
except for any conveyance through which gas is vented to the
atmosphere.
Wildcat well means a well outside known fields or the first well
drilled in an oil or gas field where no other oil and gas production
exists.
Table 1 to Subpart OOOO of Part 60--Required Minimum Initial SO2 Emission Reduction Efficiency (Zi)
----------------------------------------------------------------------------------------------------------------
Sulfur feed rate (X), LT/D
H2S content of acid gas (Y), % -------------------------------------------------------------------------------
2.0 <= X <= 5.0 5.0 < X <= 15.0 15.0 < X <= 300.0 X > 300.0
----------------------------------------------------------------------------------------------------------------
Y >= 50......................... 79.0 88.51X0.0101Y0.0125 or 99.9, whichever is smaller
----------------------------------------------------------------------------------------------------------------
20 <= Y < 50.................... 79.0 88.5X0.0101Y0.0125 or 97.9, whichever is 97.9
smaller
----------------------------------------------------------------------------------------------------------------
10 <= Y < 20.................... 79.0 88.5X0.0101Y0.0125. 93.5 93.5
or 97.9, whichever
is smaller.
----------------------------------------------------------------------------------------------------------------
Y < 10.......................... 79.0 79.0 79.0 79.0
----------------------------------------------------------------------------------------------------------------
Table 2 to Subpart OOOO of Part 60--Required Minimum SO2 Emission Reduction Efficiency (Zc)
----------------------------------------------------------------------------------------------------------------
Sulfur feed rate (X), LT/D
H2S content of acid gas (Y), % -------------------------------------------------------------------------------
2.0 <= X <= 5.0 5.0 < X <= 15.0 15.0 < X <= 300.0 X > 300.0
----------------------------------------------------------------------------------------------------------------
Y >= 50......................... 74.0 85.35X0.0144Y0.0128 or 99.9, whichever is smaller
----------------------------------------------------------------------------------------------------------------
20 <= Y < 50.................... 74.0 85.35X0.0144Y0.0128 or 97.9, whichever 97.5
is smaller
----------------------------------------------------------------------------------------------------------------
10 <= Y < 20.................... 74.0 85.35X0.0144Y0.0128 90.8 90.8
or 90.8, whichever
is smaller.
----------------------------------------------------------------------------------------------------------------
Y < 10.......................... 74.0 74.0 74.0 74.0
----------------------------------------------------------------------------------------------------------------
E = The sulfur emission rate expressed as elemental sulfur,
kilograms per hour (kg/hr) [pounds per hour (lb/hr)], rounded to one
decimal place.
R = The sulfur emission reduction efficiency achieved in percent,
carried to one decimal place.
S = The sulfur production rate, kilograms per hour (kg/hr) [pounds
per hour (lb/hr)], rounded to one decimal place.
X = The sulfur feed rate from the sweetening unit (i.e., the
H2S in the acid gas), expressed as sulfur, Mg/D(LT/D),
rounded to one decimal place.
Y = The sulfur content of the acid gas from the sweetening unit,
expressed as mole percent H2S (dry basis) rounded to one
decimal place.
Z = The minimum required sulfur dioxide (SO2) emission
reduction efficiency, expressed as percent carried to one decimal
place. Zi refers to the reduction efficiency required at
the initial performance test. Zc refers to the reduction
efficiency required on a continuous basis after compliance with
Zi has been demonstrated.
Table 3 to Subpart OOOO of Part 60--Applicability of General Provisions to Subpart OOOO
[As stated in Sec. 60.5425, you must comply with the following applicable General Provisions]
----------------------------------------------------------------------------------------------------------------
General provisions citation Subject of citation Applies to subpart? Explanation
----------------------------------------------------------------------------------------------------------------
Sec. 60.1....................... General applicability of Yes.
the General Provisions.
Sec. 60.2....................... Definitions............... Yes.................. Additional terms defined
in Sec. 60.5430.
Sec. 60.3....................... Units and abbreviations... Yes.
Sec. 60.4....................... Address................... Yes.
Sec. 60.5....................... Determination of Yes.
construction or
modification.
Sec. 60.6....................... Review of plans........... Yes.
Sec. 60.7....................... Notification and record Yes.................. Except that Sec. 60.7
keeping. only applies as
specified in Sec.
60.5420(a).
[[Page 52812]]
Sec. 60.8....................... Performance tests......... No................... Performance testing is
required for storage
vessels as specified in
40 CFR part 63, subpart
HH.
Sec. 60.9....................... Availability of Yes.
information.
Sec. 60.10...................... State authority........... Yes.
Sec. 60.11...................... Compliance with standards No................... Requirements are
and maintenance specified in subpart
requirements. OOOO.
Sec. 60.12...................... Circumvention............. Yes.
Sec. 60.13...................... Monitoring requirements... Yes.................. Continuous monitors are
required for storage
vessels.
Sec. 60.14...................... Modification.............. Yes.
Sec. 60.15...................... Reconstruction............ Yes.
Sec. 60.16...................... Priority list............. Yes.
Sec. 60.17...................... Incorporations by Yes.
reference.
Sec. 60.18...................... General control device Yes.
requirements.
Sec. 60.19...................... General notification and Yes.
reporting requirement.
----------------------------------------------------------------------------------------------------------------
PART 63--[AMENDED]
8. The authority citation for part 63 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
9. Section 63.14 is amended by:
a. Adding paragraphs (b)(69), (b)(70), (b)(71) and (b)(72); and
b. Revising paragraph (i)(1) to read as follows:
Sec. 63.14 Incorporations by reference.
* * * * *
(b) * * *
* * * * *
(69) ASTM D1945-03(2010) Standard Test Method for Analysis of
Natural Gas by Gas Chromatography, IBR approved for Sec. Sec. 63.772
and 63.1282.
(70) ASTM D5504-08 Standard Test Method for Determination of Sulfur
Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and
Chemiluminescence, IBR approved for Sec. Sec. 63.772 and 63.1282.
(71) ASTM D3588-98(2003) Standard Practice for Calculating Heat
Value, Compressibility Factor, and Relative Density of Gaseous Fuels,
IBR approved for Sec. Sec. 63.772 and 63.1282.
(72) ASTM D4891-89(2006) Standard Test Method for Heating Value of
Gases in Natural Gas Range by Stoichiometric Combustion, IBR approved
for Sec. Sec. 63.772 and 63.1282.
* * * * *
(i) * * *
(1) ANSI/ASME PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part
10, Instruments and Apparatus], issued August 31, 1981 IBR approved for
Sec. Sec. 63.309(k)(1)(iii), 63.771(e), 63.865(b), 63.1281(d),
63.3166(a)(3), 63.3360(e)(1)(iii), 63.3545(a)(3), 63.3555(a)(3),
63.4166(a)(3), 63.4362(a)(3), 63.4766(a)(3), 63.4965(a)(3),
63.5160(d)(1)(iii), 63.9307(c)(2), 63.9323(a)(3), 63.11148(e)(3)(iii),
63.11155(e)(3), 63.11162(f)(3)(iii) and (f)(4), 63.11163(g)(1)(iii) and
(g)(2), 63.11410(j)(1)(iii), 63.11551(a)(2)(i)(C), 63.11646(a)(1)(iii),
table 5 to subpart DDDDD of this part, and table 1 to subpart ZZZZZ of
this part.
* * * * *
Subpart HH--[Amended]
10. Section 63.760 is amended by:
a. Revising paragraph (a)(1) introductory text;
b. Revising paragraph (a)(1)(iii);
c. Revising paragraph (a)(2);
d. Revising paragraph (b)(1)(ii);
e. Revising paragraph (f) introductory text;
f. Revising paragraph (f)(1);
g. Revising paragraph (f)(2); and
h. Adding paragraphs (f)(7), (f)(8), (f)(9) and (f)(10) to read as
follows:
Sec. 63.760 Applicability and designation of affected source.
(a) * * *
(1) Facilities that are major or area sources of hazardous air
pollutants (HAP) as defined in Sec. 63.761. Emissions for major source
determination purposes can be estimated using the maximum natural gas
or hydrocarbon liquid throughput, as appropriate, calculated in
paragraphs (a)(1)(i) through (iii) of this section. As an alternative
to calculating the maximum natural gas or hydrocarbon liquid
throughput, the owner or operator of a new or existing source may use
the facility's design maximum natural gas or hydrocarbon liquid
throughput to estimate the maximum potential emissions. Other means to
determine the facility's major source status are allowed, provided the
information is documented and recorded to the Administrator's
satisfaction in accordance with Sec. 63.10(b)(3). A facility that is
determined to be an area source, but subsequently increases its
emissions or its potential to emit above the major source levels, and
becomes a major source, must comply thereafter with all provisions of
this subpart applicable to a major source 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.
* * * * *
(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, other than glycol circulation rate,
shall be based on either highest measured values or annual average. For
estimating maximum potential emissions from glycol dehydration units,
the glycol circulation rate used in the calculation shall be the unit's
maximum rate under its physical and operational design consistent with
the definition of potential to emit in Sec. 63.2.
(2) Facilities that process, upgrade, or store hydrocarbon liquids
prior to the point where hydrocarbon liquids enter either the Organic
Liquids Distribution (Non-gasoline) or Petroleum Refineries source
categories.
* * * * *
[[Page 52813]]
(b) * * *
(1) * * *
(ii) Each storage vessel;
* * * * *
(f) The owner or operator of an affected major source shall achieve
compliance with the provisions of this subpart by the dates specified
in paragraphs (f)(1), (f)(2), and (f)(7) through (f)(10) of this
section. The owner or operator of an affected area source shall achieve
compliance with the provisions of this subpart by the dates specified
in paragraphs (f)(3) through (f)(6) of this section.
(1) Except as specified in paragraphs (f)(7) through (10) of this
section, the owner or operator of an affected major source, the
construction or reconstruction of which commenced before February 6,
1998, shall achieve compliance with the applicable 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) Except as specified in paragraphs (f)(7) through (10) of this
section, the owner or operator of an affected major source, the
construction or reconstruction of which commences on or after February
6, 1998, shall achieve compliance with the applicable provisions of
this subpart immediately upon initial startup or June 17, 1999,
whichever date is later. Area sources, other than production field
facilities identified in (f)(9) of this section, 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.
* * * * *
(7) Each affected small glycol dehydration unit and each storage
vessel that is not a storage vessel with the potential for flash
emissions located at a major source, that commenced construction before
August 23, 2011 must achieve compliance no later than 3 years after the
date of publication of the final rule in the Federal Register, except
as provided in Sec. 63.6(i).
(8) Each affected small glycol dehydration unit and each storage
vessel that is not a storage vessel with the potential for flash
emissions, both as defined in Sec. 63.761, located at a major source,
that commenced construction on or after August 23, 2011 must achieve
compliance immediately upon initial startup or the date of publication
of the final rule in the Federal Register, whichever is later.
(9) A production field facility, as defined in Sec. 63.761,
constructed before August 23, 2011 that was previously determined to be
an area source but becomes a major source (as defined in paragraph 3 of
the major source definition in Sec. 63.761) on the date of publication
of the final rule in the Federal Register must achieve compliance no
later than 3 years after the date of publication of the final rule in
the Federal Register, except as provided in Sec. 63.6(i).
(10) Each large glycol dehydration unit, as defined in Sec.
63.761, that has complied with the provisions of this subpart prior to
August 23, 2011 by reducing its benzene emissions to less than 0.9
megagrams per year must achieve compliance no later than 90 days after
the date of publication of the final rule in the Federal Register,
except as provided in Sec. 63.6(i).
* * * * *
11. Section 63.761 is amended by:
a. Adding, in alphabetical order, new definitions for the terms
``affirmative defense,'' ``BTEX,'' ``flare,'' ``large glycol
dehydration units'' and ``small glycol dehydration units'';
b. Revising the definitions for ``associated equipment,''
``facility,'' ``glycol dehydration unit baseline operations,'' and
``temperature monitoring device''; and
c. Revising paragraph (3) of the definition for ``major source'' to
read as follows:
Sec. 63.761 Definitions.
* * * * *
Affirmative defense means, in the context of an enforcement
proceeding, a response or defense put forward by a defendant, regarding
which the defendant has the burden of proof, and the merits of which
are independently and objectively evaluated in a judicial or
administrative proceeding.
* * * * *
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.
* * * * *
BTEX means benzene, toluene, ethyl benzene and xylene.
* * * * *
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; or where natural gas is
processed, upgraded, or stored. 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.
* * * * *
Flare means a thermal oxidation system using an open flame (i.e.,
without enclosure).
* * * * *
Glycol dehydration unit baseline operations means operations
representative of the large glycol dehydration unit operations as of
June 17, 1999 and the small glycol dehydrator unit operations as of
August 23, 2011. 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.
* * * * *
Large glycol dehydration unit means a glycol dehydration unit with
an actual annual average natural gas flowrate equal to or greater than
85 thousand standard cubic meters per day and actual annual average
benzene emissions equal to or greater than 0.90
[[Page 52814]]
Mg/yr, determined according to Sec. 63.772(b).
* * * * *
Major source * * *
(3) For facilities that are production field facilities, only HAP
emissions from glycol dehydration units and storage vessels shall be
aggregated for a major source determination. For facilities that are
not production field facilities, HAP emissions from all HAP emission
units shall be aggregated for a major source determination.
* * * * *
Small glycol dehydration unit means a glycol dehydration unit,
located at a major source, with an actual annual average natural gas
flowrate less than 85 thousand standard cubic meters per day or actual
annual average benzene emissions less than 0.90 Mg/yr, determined
according to Sec. 63.772(b).
* * * * *
Temperature monitoring device means an instrument used to monitor
temperature and having a minimum accuracy of 1 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.
* * * * *
12. Section 63.762 is revised to read as follows:
Sec. 63.762 Startups and shutdowns.
(a) The provisions set forth in this subpart shall apply at all
times.
(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 owner or operator must shut down the equipment to avoid
damage due to a contemporaneous startup or shutdown, of the affected
source or a portion thereof.
(c) During startups and shutdowns, the owner or operator shall
implement measures to prevent or minimize excess emissions to the
maximum extent practical.
(d) In response to an action to enforce the standards set forth in
this subpart, you may assert an affirmative defense to a claim for
civil penalties for exceedances of such standards that are caused by
malfunction, as defined in 40 CFR 63.2. Appropriate penalties may be
assessed, however, if you fail to meet your burden of proving all the
requirements in the affirmative defense. The affirmative defense shall
not be available for claims for injunctive relief.
(1) To establish the affirmative defense in any action to enforce
such a limit, you must timely meet the notification requirements in
paragraph (d)(2) of this section, and must prove by a preponderance of
evidence that:
(i) The excess emissions:
(A) Were caused by a sudden, infrequent, and unavoidable failure of
air pollution control and monitoring equipment, process equipment, or a
process to operate in a normal or usual manner; and
(B) Could not have been prevented through careful planning, proper
design or better operation and maintenance practices; and
(C) Did not stem from any activity or event that could have been
foreseen and avoided, or planned for; and
(D) Were not part of a recurring pattern indicative of inadequate
design, operation, or maintenance; and
(ii) Repairs were made as expeditiously as possible when the
applicable emission limitations were being exceeded. Off-shift and
overtime labor were used, to the extent practicable to make these
repairs; and
(iii) The frequency, amount and duration of the excess emissions
(including any bypass) were minimized to the maximum extent practicable
during periods of such emissions; and
(iv) If the excess emissions resulted from a bypass of control
equipment or a process, then the bypass was unavoidable to prevent loss
of life, personal injury, or severe property damage; and
(v) All possible steps were taken to minimize the impact of the
excess emissions on ambient air quality, the environment, and human
health; and
(vi) All emissions monitoring and control systems were kept in
operation if at all possible, consistent with safety and good air
pollution control practices; and
(vii) All of the actions in response to the excess emissions were
documented by properly signed, contemporaneous operating logs; and
(viii) At all times, the affected source was operated in a manner
consistent with good practices for minimizing emissions; and
(ix) A written root cause analysis has been prepared to determine,
correct, and eliminate the primary causes of the malfunction and the
excess emissions resulting from the malfunction event at issue. The
analysis shall also specify, using best monitoring methods and
engineering judgment, the amount of excess emissions that were the
result of the malfunction.
(2) Notification. The owner or operator of the affected source
experiencing exceedance of its emission limit(s) during a malfunction
shall notify the Administrator by telephone or facsimile transmission
as soon as possible, but no later than two business days after the
initial occurrence of the malfunction, if it wishes to avail itself of
an affirmative defense to civil penalties for that malfunction. The
owner or operator seeking to assert an affirmative defense shall also
submit a written report to the Administrator within 45 days of the
initial occurrence of the exceedance of the standard in this subpart to
demonstrate, with all necessary supporting documentation, that it has
met the requirements set forth in paragraph (d)(1) of this section. The
owner or operator may seek an extension of this deadline for up to 30
additional days by submitting a written request to the Administrator
before the expiration of the 45 day period. Until a request for an
extension has been approved by the Administrator, the owner or operator
is subject to the requirement to submit such report within 45 days of
the initial occurrence of the exceedance.
13. Section 63.764 is amended by:
a. Revising paragraph (c)(2) introductory text;
b. Revising paragraph (e)(1) introductory text;
c. Revising paragraph (i); and
d. Adding paragraph (j) to read as follows:
Sec. 63.764 General standards.
* * * * *
(c) * * *
(2) For each storage vessel subject to this subpart, the owner or
operator shall comply with the requirements specified in paragraphs
(c)(2)(i) through (iii) of this section.
* * * * *
(e) Exemptions. (1) The owner or operator of an area source is
exempt from the requirements of paragraph (d) of this section if the
criteria listed in paragraph (e)(1)(i) or (ii) of this section are met,
except that the records of the determination of these criteria must be
maintained as required in Sec. 63.774(d)(1).
* * * * *
(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 action to
repair the leak(s) within the specified time. If action is taken to
repair the leak(s) within the specified
[[Page 52815]]
time, failure of that action to successfully repair the leak(s) is not
a violation of this standard. However, if the repairs are unsuccessful,
and a leak is detected, the owner or operator shall take further action
as required by the applicable provisions of this subpart.
(j) At all times the owner or operator must operate and maintain
any affected source, including associated air pollution control
equipment and monitoring equipment, in a manner consistent with safety
and good air pollution control practices for minimizing emissions.
Determination of whether such operation and maintenance procedures are
being used will be based on information available to the Administrator
which may include, but is not limited to, monitoring results, review of
operation and maintenance procedures, review of operation and
maintenance records, and inspection of the source.
14. Section 63.765 is amended by:
a. Revising paragraph (a);
b. Revising paragraph (b)(1);
c. Revising paragraph (c)(2); and
d. Revising paragraph (c)(3) to read as follows:
Sec. 63.765 Glycol dehydration unit process vent standards.
(a) This section applies to each glycol dehydration unit subject to
this subpart that must be controlled for air emissions as specified in
either paragraph (c)(1)(i) or paragraph (d)(1)(i) of Sec. 63.764.
(b) * * *
(1) For each glycol dehydration unit process vent, the owner or
operator shall control air emissions by either paragraph (b)(1)(i),
(ii), or (iii) of this section.
(i) The owner or operator of a large glycol dehydration unit, as
defined in Sec. 63.761, 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 of a glycol dehydration unit located at
an area source, that must be controlled as specified in Sec.
63.764(d)(1)(i), 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.
(iii) You must limit BTEX emissions from each small glycol
dehydration unit process vent, as defined in Sec. 63.761, to the limit
determined in Equation 1 of this section. The limit must be met in
accordance with one of the alternatives specified in paragraphs
(b)(1)(iii)(A) through (D) of this section.
[GRAPHIC] [TIFF OMITTED] TP23AU11.002
Where:
ELBTEX = Unit-specific BTEX emission limit, megagrams per
year;
1.10 x 10-\4\ = BTEX emission limit, grams BTEX/standard
cubic meter = ppmv;
Throughput = Annual average daily natural gas throughput, standard
cubic meters per day;
Ci,BTEX = BTEX concentration of the natural gas at the
inlet to the glycol dehydration unit, ppmv.
(A) Connect the process vent to a control device or 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(f).
(B) Meet the emissions limit through process modifications in
accordance with the requirements specified in Sec. 63.771(e).
(C) Meet the emissions limit for each small glycol dehydration unit
using a combination of process modifications and one or more control
devices through the requirements specified in paragraphs (b)(1)(iii)(A)
and (B) of this section.
(D) Demonstrate that the emissions limit is met through actual
uncontrolled operation of the small glycol dehydration unit. Document
operational parameters in accordance with the requirements specified in
Sec. 63.771(e) and emissions in accordance with the requirements
specified in Sec. 63.772(b)(2).
* * * * *
(c) * * *
(2) The owner or operator shall demonstrate, to the Administrator's
satisfaction, that the total HAP emissions to the atmosphere from the
large 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 paragraph (c)(3)(i), (ii), or (iii) of this
section, through the installation and operation of controls as
specified in paragraph (b)(1) of this section.
(i) For any large glycol dehydration unit, HAP emissions are
reduced by 95.0 percent or more.
(ii) For area source dehydration units, benzene emissions are
reduced to a level less than 0.90 megagrams per year.
(iii) For each small glycol dehydration unit, BTEX emissions are
reduced to a level less than the limit calculated by paragraph
(b)(1)(iii) of this section.
15. Section 63.766 is amended by:
a. Revising paragraph (a);
b. Revising paragraph (b) introductory text;
c. Revising paragraph (b)(1); and
d. Revising paragraph (d) to read as follows:
Sec. 63.766 Storage vessel standards.
(a) This section applies to each storage vessel (as defined in
Sec. 63.761) subject to this subpart.
(b) The owner or operator of a storage vessel (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 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).
* * * * *
(d) This section does not apply to storage vessels for which the
owner or operator is subject to and controlled under the requirements
specified in 40
[[Page 52816]]
CFR part 60, subpart Kb; or the requirements specified under 40 CFR
part 63 subparts G or CC.
16. Section 63.769 is amended by:
a. Revising paragraph (b);
b. Revising paragraph (c) introductory text; and
b. Revising paragraph (c)(8) to read as follows:
Sec. 63.769 Equipment leak standards.
* * * * *
(b) This section does not apply to ancillary equipment and
compressors for which the owner or operator is subject to and
controlled under the requirements specified in subpart H of this part;
or 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, Sec. Sec. 61.241 through 61.247, except as specified in
paragraphs (c)(1) through (8) of this section, except for valves
subject to Sec. 61.247-2(b) a leak is detected if an instrument
reading of 500 ppm or greater is measured.
* * * * *
(8) Flares, as defined in Sec. 63.761, used to comply with this
subpart shall comply with the requirements of Sec. 63.11(b).
17. Section 63.771 is amended by:
a. Revising paragraph (c)(1) introductory text;
b. Revising the heading of paragraph (d);
c. Adding paragraph (d) introductory text;
d. Revising paragraph (d)(1)(i) introductory text;
e. Revising paragraph (d)(1)(i)(C);
f. Revising paragraph (d)(1)(ii);
g. Revising paragraph (d)(1)(iii);
h. Revising paragraph (d)(4)(i);
i. Revising paragraph (d)(5)(i);
j. Revising paragraph (e)(2);
k. Revising paragraph (e)(3) introductory text;
l. Revising paragraph (e)(3)(ii); and
m. Adding paragraph (f) to read as follows:
Sec. 63.771 Control equipment requirements.
* * * * *
(c) Closed-vent system requirements. (1) The closed-vent system
shall route all gases, vapors, and fumes emitted from the material in
an emissions unit to a control device that meets the requirements
specified in paragraph (d) of this section.
* * * * *
(d) Control device requirements for sources except small glycol
dehydration units. Owners and operators of small glycol dehydration
units, shall comply with the control device requirements in paragraph
(f) of this section.
(1) * * *
(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:
* * * * *
(C) For a control device that can demonstrate a uniform combustion
zone temperature during the performance test conducted under Sec.
63.772(e), operates at a minimum temperature of 760 degrees C.
* * * * *
(ii) A vapor recovery device (e.g., carbon adsorption system or
condenser) or other non-destructive 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, as defined in Sec. 63.761, that is designed and
operated in accordance with the requirements of Sec. 63.11(b).
* * * * *
(4) * * *
(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 Sec. 63.765, Sec. 63.766, and Sec.
63.769. An owner or operator may vent more than one unit to a control
device used to comply with this subpart.
* * * * *
(5) * * *
(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. Records identifying
the schedule for replacement and records of each carbon replacement
shall be maintained as required in Sec. 63.774(b)(7)(ix). The schedule
for replacement shall be submitted with the Notification of Compliance
Status Report as specified in Sec. 63.775(d)(5)(iv). Each carbon
replacement must be reported in the Periodic Reports as specified in
Sec. 63.772(e)(2)(xii).
* * * * *
(e) * * *
(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, or BTEX limit determined in Sec.
63.765(b)(1)(iii), as applicable, 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 emission 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 or, if applicable, the BTEX limit
determined in Sec. 63.765(b)(1)(iii) for the small 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
emission reduction due to process modifications.
(3) The owner or operator that achieves a 95.0 percent HAP emission
reduction or meets the BTEX limit determined in Sec.
63.765(b)(1)(iii), as applicable, 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 or meets
the BTEX limit determined in Sec. 63.765(b)(1)(iii), as applicable,
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.
* * * * *
(ii) The owner or operator shall comply with the control device
requirements specified in paragraph (d) or (f) of this section, as
applicable, except that the emission reduction or limit achieved shall
be the emission reduction or limit specified for the control device(s)
in paragraph (e)(2) of this section.
(f) Control device requirements for small glycol dehydration units.
(1) The control device used to meet BTEX the emission limit calculated
in Sec. 63.765(b)(1)(iii) shall be one of the control devices
specified in paragraphs (f)(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 to reduce the mass content of BTEX in the gases
vented to the device as
[[Page 52817]]
determined in accordance with the requirements of Sec. 63.772(e). 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; or
(ii) A vapor recovery device (e.g., carbon adsorption system or
condenser) or other non-destructive control device that is designed and
operated to reduce the mass content of BTEX in the gases vented to the
device as determined in accordance with the requirements of Sec.
63.772(e); or
(iii) A flare, as defined in Sec. 63.761, that is designed and
operated in accordance with the requirements of Sec. 63.11(b).
(2) The owner or operator shall operate each control device in
accordance with the requirements specified in paragraphs (f)(2)(i) and
(ii) of this section.
(i) Each control device used to comply with this subpart shall be
operating at all times. 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 the requirements of either Sec.
63.772(f) or (h).
(3) For each carbon adsorption system used as a control device to
meet the requirements of paragraph (f)(1)(ii) of this section, the
owner or operator shall manage the carbon as required under (d)(5)(i)
and (ii) of this section.
18. Section 63.772 is amended by:
a. Revising paragraph (b) introductory text;
b. Revising paragraph (b)(1)(ii);
c. Revising paragraph (b)(2);
d. Adding paragraph (d);
e. Revising paragraph (e) introductory text;
f. Revising paragraphs (e)(1)(i) through (v);
g. Revising paragraph (e)(2);
h. Revising paragraph (e)(3) introductory text;
i. Revising paragraph (e)(3)(i)(B);
j. Revising paragraph (e)(3)(iv)(C)(1);
k. Adding paragraphs (e)(3)(v) and (vi);
l. Revising paragraph (e)(4) introductory text;
m. Revising paragraph (e)(4)(i);
n. Revising paragraph (e)(5);
o. Revising paragraph (f) introductory text;
p. Adding paragraphs (f)(2) through (f)(6);
q. Revising paragraph (g) introductory text;
r. Revising paragraph (g)(1) and paragraph (g)(2) introductory
text;
s. Revising paragraph (g)(2)(iii);
t. Revising paragraph (g)(3);
u. Adding paragraph (h); and
v. Adding paragraph (i) to read as follows:
Sec. 63.772 Test methods, compliance procedures, and compliance
demonstrations.
* * * * *
(b) Determination of glycol dehydration unit flowrate, benzene
emissions, or BTEX emissions. The procedures of this paragraph shall be
used by an owner or operator to determine glycol dehydration unit
natural gas flowrate, benzene emissions, or BTEX emissions.
(1) * * *
(ii) The owner or operator shall document, to the Administrator's
satisfaction, the actual annual average natural gas flowrate to the
glycol dehydration unit.
(2) The determination of actual average benzene or BTEX 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 or
BTEX emissions using the model GRI-GLYCalc\TM\, Version 3.0 or higher,
and the procedures presented in the associated GRI-GLYCalc\TM\
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 or BTEX emissions in kilograms per hour through direct
measurement using the methods in Sec. 63.772(a)(1)(i) or (ii), or an
alternative method according to Sec. 63.7(f). 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.
* * * * *
(d) Test procedures and compliance demonstrations for small glycol
dehydration units. This paragraph applies to the test procedures for
small dehydration units.
(1) If the owner or operator is using a control device to comply
with the emission limit in Sec. 63.765(b)(1)(iii), the requirements of
paragraph (e) of this section apply. Compliance is demonstrated using
the methods specified in paragraph (f) of this section.
(2) If no control device is used to comply with the emission limit
in Sec. 63.765(b)(1)(iii), the owner or operator must determine the
glycol dehydration unit BTEX emissions as specified in paragraphs
(d)(2)(i) through (iii) of this section. Compliance is demonstrated if
the BTEX emissions determined as specified in paragraphs (d)(2)(i)
through (iii) are less than the emission limit calculated using the
equation in Sec. 63.765(b)(1)(iii).
(i) Method 1 or 1A, 40 CFR part 60, appendix A, as appropriate,
shall be used for selection of the sampling sites at the outlet of the
glycol dehydration unit process vent. Any references to particulate
mentioned in Methods 1 and 1A do not apply to this section.
(ii) The gas volumetric flowrate shall be determined using Method
2, 2A, 2C, or 2D, 40 CFR part 60, appendix A, as appropriate.
(iii) The BTEX emissions from the outlet of the glycol dehydration
unit process vent shall be determined using the procedures specified in
paragraph (e)(3)(v) of this section. As an alternative, the mass rate
of BTEX at the outlet of the glycol dehydration unit process vent may
be calculated using the model GRI-GLYCalc\TM\, Version 3.0 or higher,
and the procedures presented in the associated GRI-GLYCalc\TM\
Technical Reference Manual. Inputs to the model shall be representative
of actual operating conditions of the glycol dehydration unit and shall
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). When the
BTEX mass rate is calculated for glycol dehydration units using the
model GRI-GLYCalc\TM\, all BTEX measured by Method 18, 40 CFR part 60,
appendix A, shall be summed.
(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), (e)(3)(ii) or (f)(1)
using a performance test as specified in paragraph (e)(3) of this
section. Owners or operators using a condenser have the option to use 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
[[Page 52818]]
to control emissions from a glycol dehydration unit process vent. As an
alternative to conducting a performance test under this section for
combustion control devices, a control device that can be demonstrated
to meet the performance requirements of Sec. 63.771(d)(1), (e)(3)(ii)
or (f)(1) through a performance test conducted by the manufacturer, as
specified in paragraph (h) of this section can be used.
(1) * * *
(i) Except as specified in paragraph (e)(2) of this section, a
flare, as defined in Sec. 63.761, that is designed and operated in
accordance with Sec. 63.11(b);
(ii) Except for control devices used for small glycol dehydration
units, a boiler or process heater with a design heat input capacity of
44 megawatts or greater;
(iii) Except for control devices used for small glycol dehydration
units, a boiler or process heater into which the vent stream is
introduced with the primary fuel or is used as the primary fuel;
(iv) Except for control devices used for small glycol dehydration
units, 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) Except for control devices used for small glycol dehydration
units, 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.
* * * * *
(2) An owner or operator shall design and operate each flare, as
defined in Sec. 63.761, in accordance with the requirements specified
in Sec. 63.11(b) and the compliance determination shall be conducted
using Method 22 of 40 CFR part 60, appendix A, to determine visible
emissions.
(3) For a performance test conducted to demonstrate that a control
device meets the requirements of Sec. 63.771(d)(1), (e)(3)(ii) or
(f)(1), the owner or operator shall use the test methods and procedures
specified in paragraphs (e)(3)(i) through (v) of this section. The
initial and periodic performance tests shall be conducted according to
the schedule specified in paragraph (e)(3)(vi) of this section.
(i) * * *
(B) To determine compliance with the enclosed combustion device
total HAP concentration limit specified in Sec. 63.765(b)(1)(iii), or
the BTEX emission limit specified in Sec. 63.771(f)(1) the sampling
site shall be located at the outlet of the combustion device.
* * * * *
(iv) * * *
(C) * * *
(1) The emission rate correction factor for excess air, integrated
sampling and analysis procedures of Method 3A or 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.
* * * * *
(v) To determine compliance with the BTEX emission limit specified
in Sec. 63.771(f)(1) the owner or operator shall use one of the
following methods: Method 18, 40 CFR part 60, appendix A; ASTM D6420-99
(2004), as specified in Sec. 63.772(a)(1)(ii); or any other method or
data that have been validated according to the applicable procedures in
Method 301, 40 CFR part 63, appendix A. The following procedures shall
be used to calculate BTEX emissions:
(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 BTEX (Eo) shall be computed using
the equations and procedures specified in paragraphs (e)(3)(v)(B)(1)
and (2) of this section.
(1) The following equation shall be used:
[GRAPHIC] [TIFF OMITTED] TP23AU11.003
Where:
Eo= Mass rate of BTEX at the outlet of the control
device, dry basis, kilogram per hour.
Coj= Concentration of sample component j of the gas
stream at the outlet of the control device, dry basis, parts per
million by volume.
Moj= Molecular weight of sample component j of the gas
stream at the outlet of the control device, gram/gram-mole.
Qo= Flowrate of gas stream at the outlet of the control
device, dry standard cubic meter per minute.
K2= Constant, 2.494 x 10-\6\ (parts per
million) (gram-mole per standard cubic meter) (kilogram/gram)
(minute/hour), where standard temperature (gram-mole per standard
cubic meter) is 20 degrees C.
n = Number of components in sample.
(2) When the BTEX mass rate is calculated, only BTEX compounds
measured by Method 18, 40 CFR part 60, appendix A, or ASTM D6420-99
(2004) as specified in Sec. 63.772(a)(1)(ii), shall be summed using
the equations in paragraph (e)(3)(v)(B)(1) of this section.
(vi) The owner or operator shall conduct performance tests
according to the schedule specified in paragraphs (e)(3)(vi)(A) and (B)
of this section.
(A) An initial performance test shall be conducted within 180 days
after the compliance date that is specified for each affected source in
Sec. 63.760(f)(7) through (8), except that the initial performance
test for existing combustion control devices at existing major sources
shall be conducted no later than 3 years after the date of publication
of the final rule in the Federal Register. If the owner or operator of
an existing combustion control device at an existing major source
chooses to replace such device with a control device whose model is
tested under Sec. 63.772(h), then the newly installed device shall
comply with all provisions of this subpart no later than 3 years after
the date of publication of the final rule in the Federal Register. The
performance test results shall be submitted in the Notification of
Compliance Status Report as required in Sec. 63.775(d)(1)(ii).
(B) Periodic performance tests shall be conducted for all control
devices required to conduct initial performance tests except as
specified in paragraphs (e)(3)(vi)(B)(1) and (2) of this section. The
first periodic performance test shall be conducted no later than 60
months after the initial performance test required in paragraph
(e)(3)(vi)(A) of this section. Subsequent periodic performance tests
shall be conducted at intervals no longer than 60 months following the
previous periodic performance test or whenever a source desires to
establish a new operating limit. The periodic performance test results
must be submitted in the next Periodic Report as specified in Sec.
63.775(e)(2)(xi). Combustion control devices meeting the criteria in
either paragraph (e)(3)(vi)(B)(1) or (2) of this section are not
required to conduct periodic performance tests.
(1) A control device whose model is tested under, and meets the
criteria of, Sec. 63.772(h), or
(2) A combustion control device tested under Sec. 63.772(e) that
meets the outlet TOC or HAP performance level specified in Sec.
63.771(d)(1)(i)(B) and that
[[Page 52819]]
establishes a correlation between firebox or combustion chamber
temperature and the TOC or HAP performance level.
(4) For a condenser design analysis conducted to meet the
requirements of Sec. 63.771(d)(1), (e)(3)(ii), or (f)(1), 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 condenser design analysis shall include an analysis of 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 condenser design analysis, an owner or operator may elect to use
the procedures specified in paragraph (e)(5) of this section.
* * * * *
(5) As an alternative to the procedures in paragraph (e)(4)(i) 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-GLYCalc\TM\, Version 3.0 or higher, to generate a
condenser performance curve.
(f) Compliance demonstration for control device performance
requirements. This paragraph applies to the demonstration of compliance
with the control device performance requirements specified in Sec.
63.771(d)(1)(i), (e)(3) and (f)(1). Compliance shall be demonstrated
using the requirements in paragraphs (f)(1) through (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), (e)(3) or (f)(1) 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.
* * * * *
(2) The owner or operator shall calculate the daily average of the
applicable monitored parameter in accordance with Sec. 63.773(d)(4)
except that the inlet gas flow rate to the control device shall not be
averaged.
(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. For inlet gas flow
rate, compliance with the operating parameter limit is achieved when
the value is equal to or less than the value established under Sec.
63.772(h).
(4) Except for periods of monitoring system malfunctions, repairs
associated with monitoring system malfunctions, and required monitoring
system quality assurance or quality control activities (including, as
applicable, system accuracy audits and required zero and span
adjustments), the CMS required in Sec. 63.773(d) must be operated at
all times the affected source is operating. A monitoring system
malfunction is any sudden, infrequent, not reasonably preventable
failure of the monitoring system to provide valid data. Monitoring
system failures that are caused in part by poor maintenance or careless
operation are not malfunctions. Monitoring system repairs are required
to be completed in response to monitoring system malfunctions and to
return the monitoring system to operation as expeditiously as
practicable.
(5) Data recorded during monitoring system malfunctions, repairs
associated with monitoring system malfunctions, or required monitoring
system quality assurance or control activities may not be used in
calculations used to report emissions or operating levels. All the data
collected during all other required data collection periods must be
used in assessing the operation of the control device and associated
control system.
(6) Except for periods of monitoring system malfunctions, repairs
associated with monitoring system malfunctions, and required quality
monitoring system quality assurance or quality control activities
(including, as applicable, system accuracy audits and required zero and
span adjustments), failure to collect required data is a deviation of
the monitoring requirements.
(g) Compliance demonstration with percent reduction or emission
limit performance requirements--condensers. This paragraph applies to
the demonstration of compliance with the performance requirements
specified in Sec. 63.771(d)(1)(ii),(e)(3) or (f)(1) for condensers.
Compliance shall be demonstrated using the procedures in paragraphs
(g)(1) through (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). For sources
required to meet the BTEX limit in accordance with Sec. 63.771(e) or
(f)(1) the owner or operator shall identify the minimum percent
reduction necessary to meet the BTEX limit.
(2) Compliance with the requirements in Sec.
63.771(d)(1)(ii),(e)(3) or (f)(1) shall be demonstrated by the
procedures in paragraphs (g)(2)(i) through (iii) 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 owner or operator
shall calculate the 365-day average HAP, or BTEX, emission reduction,
as appropriate, from the condenser efficiencies as 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. 63.771(e), the 365-day average HAP, or BTEX, emission reduction
shall be calculated using the emission reduction achieved through
process modifications and the condenser efficiency as 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, or BTEX, emission reduction, as appropriate, shall
calculate the average HAP, or BTEX emission reduction, as appropriate,
for the first 120 days of operation after the compliance dates. For
sources required to meet the overall 95.0 percent reduction
requirement, compliance is achieved if the 120-day average HAP emission
reduction is equal to or greater than 90.0 percent. For sources
required to meet the BTEX limit under Sec. 63.765(b)(1)(iii),
compliance is achieved if the average BTEX emission reduction is at
least 95.0 percent of the required 365-day value identified under
paragraph (g)(1) of this section (i.e., at least 76.0 percent if the
365-day design value is 80.0 percent).
(B) After 120 days and no more than 364 days of operation after the
[[Page 52820]]
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. For sources required to meet the
overall 95.0-percent reduction requirement, compliance with the
performance requirements is achieved if the average HAP emission
reduction is equal to or greater than 90.0 percent. For sources
required to meet the BTEX limit under Sec. 63.765(b)(1)(iii),
compliance is achieved if the average BTEX emission reduction is at
least 95.0 percent of the required 365-day value identified under
paragraph (g)(1) of this section (i.e., at least 76.0 percent if the
365-day design value is 80.0 percent).
(3) If the owner or operator has data for 365 days or more of
operation, compliance is achieved based on the applicable criteria in
paragraphs (g)(3)(i) or (ii) of this section.
(i) For sources meeting the HAP emission reduction specified in
Sec. 63.771(d)(1)(ii) or (e)(3) the average HAP emission reduction
calculated in paragraph (g)(2)(iii) of this section is equal to or
greater than 95.0 percent.
(ii) For sources required to meet the BTEX limit under Sec.
63.771(e)(3) or (f)(1), compliance is achieved if the average BTEX
emission reduction calculated in paragraph (g)(2)(iii) of this section
is equal to or greater than the minimum percent reduction identified in
paragraph (g)(1) of this section.
* * * * *
(h) Performance testing for combustion control devices--
manufacturers' performance test. (1) This paragraph applies to the
performance testing of a combustion control device conducted by the
device manufacturer. The manufacturer shall demonstrate that a specific
model of control device achieves the performance requirements in (h)(7)
of this section by conducting a performance test as specified in
paragraphs (h)(2) through (6) of this section.
(2) Performance testing shall consist of three one-hour (or longer)
test runs for each of the four following firing rate settings making a
total of 12 test runs per test. Propene (propylene) gas shall be used
for the testing fuel. All fuel analyses shall be performed by an
independent third-party laboratory (not affiliated with the control
device manufacturer or fuel supplier).
(i) 90-100 percent of maximum design rate (fixed rate).
(ii) 70-100-70 percent (ramp up, ramp down). Begin the test at 70
percent of the maximum design rate. Within the first 5 minutes, ramp
the firing rate to 100 percent of the maximum design rate. Hold at 100
percent for 5 minutes. In the 10-15 minute time range, ramp back down
to 70 percent of the maximum design rate. Repeat three more times for a
total of 60 minutes of sampling.
(iii) 30-70-30 percent (ramp up, ramp down). Begin the test at 30
percent of the maximum design rate. Within the first 5 minutes, ramp
the firing rate to 70 percent of the maximum design rate. Hold at 70
percent for 5 minutes. In the 10-15 minute time range, ramp back down
to 30 percent of the maximum design rate. Repeat three more times for a
total of 60 minutes of sampling.
(iv) 0-30-0 percent (ramp up, ramp down). Begin the test at 0
percent of the maximum design rate. Within the first 5 minutes, ramp
the firing rate to 100 percent of the maximum design rate. Hold at 30
percent for 5 minutes. In the 10-15 minute time range, ramp back down
to 0 percent of the maximum design rate. Repeat three more times for a
total of 60 minutes of sampling.
(3) All models employing multiple enclosures shall be tested
simultaneously and with all burners operational. Results shall be
reported for the each enclosure individually and for the average of the
emissions from all interconnected combustion enclosures/chambers.
Control device operating data shall be collected continuously
throughout the performance test using an electronic Data Acquisition
System and strip chart. Data shall be submitted with the test report in
accordance with paragraph (8)(iii) of this section.
(4) Inlet testing shall be conducted as specified in paragraphs
(h)(4)(i) through (iii) of this section.
(i) The fuel flow metering system shall be located in accordance
with Method 2A, 40 CFR part 60, appendix A-1, (or other approved
procedure) to measure fuel flow rate at the control device inlet
location. The fitting for filling fuel sample containers shall be
located a minimum of 8 pipe diameters upstream of any inlet fuel flow
monitoring meter.
(ii) Inlet flow rate shall be determined using Method 2A, 40 CFR
part 60, appendix A-1. Record the start and stop reading for each 60-
minute THC test. Record the gas pressure and temperature at 5-minute
intervals throughout each 60-minute THC test.
(iii) Inlet fuel sampling shall be conducted in accordance with the
criteria in paragraphs (h)(4)(iii)(A) and (B) of this section.
(A) At the inlet fuel sampling location, securely connect a
Silonite-coated stainless steel evacuated canister fitted with a flow
controller sufficient to fill the canister over a 1 hour period.
Filling shall be conducted as specified in the following:
(1) Open the canister sampling valve at the beginning of the total
hydrocarbon (THC) test, and close the canister at the end of the THC
test.
(2) Fill one canister for each THC test run.
(3) Label the canisters individually and record on a chain of
custody form.
(B) Each fuel sample shall be analyzed using the following methods.
The results shall be included in the test report.
(1) Hydrocarbon compounds containing between one and five atoms of
carbon plus benzene using ASTM D1945-03.
(2) Hydrogen (H2), carbon monoxide (CO), carbon dioxide
(CO2), nitrogen (N2), oxygen (O2)
using ASTM D1945-03.
(3) Carbonyl sulfide, carbon disulfide plus mercaptans using ASTM
D5504.
(4) Higher heating value using ASTM D3588-98 or ASTM D4891-89.
(5) Outlet testing shall be conducted in accordance with the
criteria in paragraphs (h)(5)(i) through (v) of this section.
(i) Sampling and flowrate measured in accordance with the
following:
(A) The outlet sampling location shall be a minimum of 4 equivalent
stack diameters downstream from the highest peak flame or any other
flow disturbance, and a minimum of one equivalent stack diameter
upstream of the exit or any other flow disturbance. A minimum of two
sample ports shall be used.
(B) Flow rate shall be measured using Method 1, 40 CFR part 60,
Appendix 1, for determining flow measurement traverse point location;
and Method 2, 40 CFR part 60, Appendix 1, shall be used to measure duct
velocity. If low flow conditions are encountered (i.e., velocity
pressure differentials less than 0.05 inches of water) during the
performance test, a more sensitive manometer shall be used to obtain an
accurate flow profile.
(ii) Molecular weight shall be determined as specified in
paragraphs (h)(4)(iii)(B), (h)(5)(ii)(A), and (h)(5)(ii)(B) of this
section.
(A) An integrated bag sample shall be collected during the Method
4, 40 CFR part 60, Appendix A, moisture test. Analyze the bag sample
using a gas chromatograph-thermal conductivity detector (GC-TCD)
analysis meeting the following criteria:
(1) Collect the integrated sample throughout the entire test, and
collect
[[Page 52821]]
representative volumes from each traverse location.
(2) The sampling line shall be purged with stack gas before opening
the valve and beginning to fill the bag.
(3) The bag contents shall be kneaded or otherwise vigorously mixed
prior to the GC analysis.
(4) The GC-TCD calibration procedure in Method 3C, 40 CFR part 60,
Appendix A, shall be modified by using EPAAlt-045 as follows: For the
initial calibration, triplicate injections of any single concentration
must agree within 5 percent of their mean to be valid. The calibration
response factor for a single concentration re-check must be within 10
percent of the original calibration response factor for that
concentration. If this criterion is not met, the initial calibration
using at least three concentration levels shall be repeated.
(B) Report the molecular weight of: O2, CO2,
methane (CH4), and N2 and include in the test report
submitted under Sec. 63.775(d)(iii). Moisture shall be determined
using Method 4, 40 CFR part 60, Appendix A. Traverse both ports with
the Method 4, 40 CFR part 60, Appendix A, sampling train during each
test run. Ambient air shall not be introduced into the Method 3C, 40
CFR part 60, Appendix A, integrated bag sample during the port change.
(iii) Carbon monoxide shall be determined using Method 10, 40 CFR
part 60, Appendix A. The test shall be run at the same time and with
the sample points used for the EPA Method 25A, 40 CFR part 60, Appendix
A, testing. An instrument range of 0-10 per million by volume-dry
(ppmvd) shall be used.
(iv) Visible emissions shall be determined using Method 22, 40 CFR
part 60, Appendix A. The test shall be performed continuously during
each test run. A digital color photograph of the exhaust point, taken
from the position of the observer and annotated with date and time,
will be taken once per test run and the four photos included in the
test report.
(6) Total hydrocarbons (THC) shall be determined as specified by
the following criteria:
(i) Conduct THC sampling using Method 25A, 40 CFR part 60, Appendix
A, except the option for locating the probe in the center 10 percent of
the stack shall not be allowed. The THC probe must be traversed to 16.7
percent, 50 percent, and 83.3 percent of the stack diameter during the
testing.
(ii) A valid test shall consist of three Method 25A, 40 CFR part
60, Appendix A, tests, each no less than 60 minutes in duration.
(iii) A 0-10 parts per million by volume-wet (ppmvw) (as propane)
measurement range is preferred; as an alternative a 0-30 ppmvw (as
carbon) measurement range may be used.
(iv) Calibration gases will be propane in air and be certified
through EPA Protocol 1--``EPA Traceability Protocol for Assay and
Certification of Gaseous Calibration Standards,'' September 1997, as
amended August 25, 1999, EPA-600/R-97/121 (or more recent if updated
since 1999).
(v) THC measurements shall be reported in terms of ppmvw as
propane.
(vi) THC results shall be corrected to 3 percent CO2, as
measured by Method 3C, 40 CFR part 60, Appendix A.
(vii) Subtraction of methane/ethane from the THC data is not
allowed in determining results.
(7) Performance test criteria:
(i) The control device model tested must meet the criteria in
paragraphs (h)(7)(i)(A) through (C) of this section:
(A) Method 22, 40 CFR part 60, Appendix A, results under paragraph
(h)(5)(v) of this section with no indication of visible emissions, and
(B) Average Method 25A, 40 CFR part 60, Appendix A, results under
paragraph (h)(6) of this section equal to or less than 10.0 ppmvw THC
as propane corrected to 3.0 percent CO2, and
(C) Average CO emissions determined under paragraph (h)(5)(iv) of
this section equal to or less than 10 parts ppmvd, corrected to 3.0
percent CO2.
(ii) The manufacturer shall determine a maximum inlet gas flow rate
which shall not be exceeded for each control device model to achieve
the criteria in paragraph (h)(7)(i) of this section.
(iii) A control device meeting the criteria in paragraphs
(h)(7)(i)(A) through (C) of this section will have demonstrated a
destruction efficiency of 98.0 percent for HAP regulated under this
subpart.
(8) The owner or operator of a combustion control device model
tested under this section shall submit the information listed in
paragraphs (h)(8)(i) through (iii) of this section in the test report
required under Sec. 63.775(d)(1)(iii).
(i) Full schematic of the control device and dimensions of the
device components.
(ii) Design net heating value (minimum and maximum) of the device.
(iii) Test fuel gas flow range (in both mass and volume). Include
the minimum and maximum allowable inlet gas flow rate.
(iv) Air/stream injection/assist ranges, if used.
(v) The test parameter ranges listed in paragraphs (h)(8)(v)(A)
through (O) of this section, as applicable for the tested model.
(A) Fuel gas delivery pressure and temperature.
(B) Fuel gas moisture range.
(C) Purge gas usage range.
(D) Condensate (liquid fuel) separation range.
(E) Combustion zone temperature range. This is required for all
devices that measure this parameter.
(F) Excess combustion air range.
(G) Flame arrestor(s).
(H) Burner manifold pressure.
(I) Pilot flame sensor.
(J) Pilot flame design fuel and fuel usage.
(K) Tip velocity range.
(L) Momentum flux ratio.
(M) Exit temperature range.
(N) Exit flow rate.
(O) Wind velocity and direction.
(vi) The test report shall include all calibration quality
assurance/quality control data, calibration gas values, gas cylinder
certification, and strip charts annotated with test times and
calibration values.
(i) Compliance demonstration for combustion control devices--
manufacturers' performance test. This paragraph applies to the
demonstration of compliance for a combustion control device tested
under the provisions in paragraph (h) of this section. Owners or
operators shall demonstrate that a control device achieves the
performance requirements of Sec. 63.771(d)(1), (e)(3)(ii) or (f)(1),
by installing a device tested under paragraph (h) of this section and
complying with the following criteria:
(1) The inlet gas flow rate shall meet the range specified by the
manufacturer. Flow rate shall be measured as specified in Sec.
63.773(d)(3)(i)(H)(1).
(2) A pilot flame shall be present at all times of operation. The
pilot flame shall be monitored in accordance with Sec.
63.773(d)(3)(i)(H)(2).
(3) Devices shall be operated with no visible emissions, except for
periods not to exceed a total of 5 minutes during any 2 consecutive
hours. A visible emissions test using Method 22, 40 CFR part 60,
Appendix A, shall be performed monthly. The observation period shall be
2 hours and shall be used according to Method 22.
(4) Compliance with the operating parameter limit is achieved when
the following criteria are met:
(i) The inlet gas flow rate monitored under paragraph (i)(1) of
this section is equal to or below the maximum established by the
manufacturer; and
(ii) The pilot flame is present at all times; and
(iii) During the visible emissions test performed under paragraph
(i)(3) of this
[[Page 52822]]
section the duration of visible emissions does not exceed a total of 5
minutes during the observation period. Devices failing the visible
emissions test shall follow the requirements in paragraphs
(i)(4)(iii)(A) and (B) of this section.
(A) Following the first failure, the fuel nozzle(s) and burner
tubes shall be replaced.
(B) If, following replacement of the fuel nozzle(s) and burner
tubes as specified in paragraph (i)(4)(iii)(A), the visible emissions
test is not passed in the next scheduled test, either a performance
test shall be performed under paragraph (e) of this section, or the
device shall be replaced with another control device whose model was
tested, and meets, the requirements in paragraph (h) of this section.
19. Section 63.773 is amended by:
a. Adding paragraph (b);
b. Revising paragraph (d)(1) introductory text;
c. Revising paragraph (d)(1)(ii) and adding paragraphs (d)(1)(iii)
and (iv);
d. Revising paragraphs (d)(2)(i) and (d)(2)(ii);
e. Revising paragraphs (d)(3)(i)(A) and (B);
f. Revising paragraphs (d)(3)(i)(D) and (E);
g. Revising paragraphs (d)(3)(i)(F)(1) and (2);
h. Revising paragraph (d)(3)(i)(G);
i. Adding paragraph (d)(3)(i)(H);
j. Revising paragraph (d)(4);
k. Revising paragraph (d)(5)(i);
l. Revising paragraphs (d)(5)(ii)(A) through (C);
m. Revising paragraphs (d)(6)(ii) and (iii);
n. Adding paragraph (d)(6)(vi);
o. Revising paragraph (d)(8)(i)(A); and
p. Revising paragraph (d)(8)(ii) to read as follows:
Sec. 63.773 Inspection and monitoring requirements.
* * * * *
(b) The owner or operator of a control device whose model was
tested under Sec. 63.772(h) shall develop an inspection and
maintenance plan for each control device. At a minimum, the plan shall
contain the control device manufacturer's recommendations for ensuring
proper operation of the device. Semi-annual inspections shall be
conducted for each control device with maintenance and replacement of
control device components made in accordance with the plan.
* * * * *
(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. Owners or operators that install
and operate a flare in accordance with Sec. 63.771(d)(1)(iii) or
(f)(1)(iii) are exempt from the requirements of paragraphs (d)(4) and
(5) 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), (e)(3) or (f)(1). Each continuous parameter monitoring
system shall meet the following specifications and requirements:
* * * * *
(ii) A site-specific monitoring plan must be prepared that
addresses the monitoring system design, data collection, and the
quality assurance and quality control elements outlined in paragraph
(d) of this section and in Sec. 63.8(d). Each CPMS must be installed,
calibrated, operated, and maintained in accordance with the procedures
in your approved site-specific monitoring plan. Using the process
described in Sec. 63.8(f)(4), you may request approval of monitoring
system quality assurance and quality control procedures alternative to
those specified in paragraphs (d)(1)(ii)(A) through (E) of this section
in your site-specific monitoring plan.
(A) The performance criteria and design specifications for the
monitoring system equipment, including the sample interface, detector
signal analyzer, and data acquisition and calculations;
(B) Sampling interface (e.g., thermocouple) location such that the
monitoring system will provide representative measurements;
(C) Equipment performance checks, system accuracy audits, or other
audit procedures;
(D) Ongoing operation and maintenance procedures in accordance with
provisions in Sec. 63.8(c)(1) and (c)(3); and
(E) Ongoing reporting and recordkeeping procedures in accordance
with provisions in Sec. 63.10(c), (e)(1), and (e)(2)(i).
(iii) The owner or operator must conduct the CPMS equipment
performance checks, system accuracy audits, or other audit procedures
specified in the site-specific monitoring plan at least once every 12
months.
(iv) The owner or operator must conduct a performance evaluation of
each CPMS in accordance with the site-specific monitoring plan.
(2) * * *
(i) Except for control devices for small glycol dehydration units,
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) Except for control devices for small glycol dehydration units,
a boiler or process heater with a design heat input capacity equal to
or greater than 44 megawatts.
(3) * * *
(i) * * *
(A) For a thermal vapor incinerator that demonstrates during the
performance test conducted under Sec. 63.772(e) that the combustion
zone temperature is an accurate indicator of performance, a temperature
monitoring device equipped with a continuous recorder. The monitoring
device shall have a minimum accuracy of 1 percent of the
temperature being monitored in degrees C, or 2.5 degrees
C, whichever value is greater. The temperature sensor shall be
installed at a location representative of the combustion zone
temperature.
(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 1 percent of the temperature being monitored in degrees
C, or 2.5 degrees 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.
* * * * *
(D) For a boiler or process heater a temperature monitoring device
equipped with a continuous recorder. The temperature monitoring device
shall have a minimum accuracy of 1 percent of the
temperature being monitored in degrees C, or 2.5 degrees
C, whichever value is greater. The temperature sensor shall be
installed at a location representative of the combustion zone
temperature.
(E) For a condenser, a temperature monitoring device equipped with
a continuous recorder. The temperature monitoring device shall have a
minimum accuracy of 1 percent of the temperature being
monitored in degrees C, or 2.8 degrees C, whichever value
is greater. The temperature sensor shall be installed at a location in
the exhaust vent stream from the condenser.
(F) * * *
(1) A continuous parameter monitoring system to measure and
[[Page 52823]]
record the average total regeneration stream mass flow or volumetric
flow during each carbon bed regeneration cycle. The flow sensor must
have a measurement sensitivity of 5 percent of the flow rate or 10
cubic feet per minute, whichever is greater. The mechanical connections
for leakage must be checked at least every month, and a visual
inspection must be performed at least every 3 months of all components
of the flow CPMS for physical and operational integrity and all
electrical connections for oxidation and galvanic corrosion if your
flow CPMS is not equipped with a redundant flow sensor; 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 1 percent of the temperature being monitored in degrees C, or
2.5 degrees 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) shall be based on the total carbon working capacity of the
control device and source operating schedule.
(H) For a control device model whose model is tested under Sec.
63.772(h):
(1) A continuous monitoring system that measures gas flow rate at
the inlet to the control device. The monitoring instrument shall have
an accuracy of plus or minus 2 percent or better.
(2) A heat sensing monitoring device equipped with a continuous
recorder that indicates the continuous ignition of the pilot flame.
* * * * *
(4) Using the data recorded by the monitoring system, except for
inlet gas flow rate, the owner or operator must calculate the daily
average value for each monitored operating parameter for each operating
day. If the emissions unit operation is continuous, the operating day
is a 24-hour period. If the 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) * * *
(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), (e)(3)(ii) or (f)(1).
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. 63.772(e)(3) to demonstrate
that the control device achieves the applicable performance
requirements specified in Sec. 63.771(d)(1), (e)(3)(ii) or (f)(1),
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 a condenser
design analysis or control device manufacturer recommendations or a
combination of both.
(B) If the owner or operator uses a condenser 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), (e)(3)(ii) or (f)(1),
then the minimum operating parameter value or the maximum operating
parameter value shall be established based on the condenser design
analysis and may be supplemented by the condenser manufacturer's
recommendations.
(C) If the owner or operator operates a control device where the
performance test requirement was met under Sec. 63.772(h) to
demonstrate that the control device achieves the applicable performance
requirements specified in Sec. 63.771(d)(1), (e)(3)(ii) or (f)(1),
then the maximum inlet gas flow rate shall be established based on the
performance test and supplemented, as necessary, by the manufacturer
recommendations.
(ii) * * *
(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), (e)(3)(ii) or (f)(1), 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) to
demonstrate that the condenser achieves the applicable performance
requirements specified in Sec. 63.771(d)(1), (e)(3)(ii) or (f)(1),
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 paragraph (d)(5)(ii)(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-GLYCalc\TM\, Version 3.0 or higher, to generate a condenser
performance curve.
* * * * *
(6) * * *
(ii) For sources meeting Sec. 63.771(d)(1)(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. For sources meeting Sec. 63.771(f)(1), 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 of the identified 365-day
required percent reduction.
(iii) For sources meeting Sec. 63.771(d)(1)(ii), 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. For sources meeting Sec. 63.771(d)(1)(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 the identified 365-day required percent reduction.
* * * * *
(vi) For control device whose model is tested under Sec. 63.772(h)
an excursion occurs when:
(A) The inlet gas flow rate exceeds the maximum established during
the test conducted under Sec. 63.772(h).
(B) Failure of the monthly visible emissions test conducted under
Sec. 63.772(i)(3) occurs.
* * * * *
(8) * * *
(i) * * *
(A) During a malfunction when the affected facility is operated
during such
[[Page 52824]]
period in accordance with Sec. 63.6(e)(1); or
* * * * *
(ii) For each control device, or combinations of control devices
installed on the same 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.
* * * * *
20. Section 63.774 is amended by:
a. Revising paragraph (b)(3) introductory text;
b. Removing and reserving paragraph (b)(3)(ii);
c. Revising paragraph (b)(4)(ii) introductory text;
d. Adding paragraph (b)(4)(ii)(C);
e. Adding paragraph (b)(7)(ix); and
f. Adding paragraphs (g) through (i) to read as follows:
Sec. 63.774 Recordkeeping requirements.
* * * * *
(b) * * *
(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 or failed to collect required data.
* * * * *
(ii) [Reserved]
* * * * *
(4) * * *
(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) through (C) of this section.
* * * * *
(C) For control device whose model is tested under Sec. 63.772(h),
the records required in paragraph (h) of this section.
* * * * *
(7) * * *
(ix) Records identifying the carbon replacement schedule under
Sec. 63.771(d)(5) and records of each carbon replacement.
* * * * *
(g) The owner or operator of an affected source subject to this
subpart shall maintain records of the occurrence and duration of each
malfunction of operation (i.e., process equipment) or the air pollution
control equipment and monitoring equipment. The owner or operator shall
maintain records of actions taken during periods of malfunction to
minimize emissions in accordance with Sec. 63.764(a), including
corrective actions to restore malfunctioning process and air pollution
control and monitoring equipment to its normal or usual manner of
operation.
(h) Record the following when using a control device whose model is
tested under Sec. 63.772(h) to comply with Sec. 63.771(d), (e)(3)(ii)
and (f)(1):
(1) All visible emission readings and flowrate measurements made
during the compliance determination required by Sec. 63.772(i); and
(2) All hourly records and other recorded periods when the pilot
flame is absent.
(i) The date the semi-annual maintenance inspection required under
Sec. 63.773(b) is performed. Include a list of any modifications or
repairs made to the control device during the inspection and other
maintenance performed such as cleaning of the fuel nozzles.
21. Section 63.775 is amended by:
a. Revising paragraph (b)(1);
b. Revising paragraph (b)(6);
c. Removing and reserving paragraph (b)(7);
d. Revising paragraph (c)(1);
e. Revising paragraph (c)(6);
f. Revising paragraph (c)(7)(i);
g. Revising paragraph (d)(1)(i);
h. Revising paragraph (d)(1)(ii) introductory text;
i. Revising paragraph (d)(5)(ii);
j. Adding paragraph (d)(5)(iv);
k. Revising paragraph (d)(11);
l. Adding paragraphs (d)(13) and (d)(14);
m. Revising paragraphs (e)(2) introductory text, (e)(2)(ii)(B) and
(C);
n. Adding paragraphs (e)(2)(ii)(E) and (F);
o. Adding paragraphs (e)(2)(xi) through (xiii); and
p. Adding paragraph (g) to read as follows:
Sec. 63.775 Reporting requirements.
* * * * *
(b) * * *
(1) The initial notifications required for existing affected
sources under Sec. 63.9(b)(2) shall be submitted as provided in
paragraphs (b)(1)(i) and (ii) of this section.
(i) Except as otherwise provided in paragraph (ii), the initial
notifications 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.
(ii) An affected source identified under Sec. 63.760(f)(7) or (9)
shall submit an initial notification required for existing affected
sources under Sec. 63.9(b)(2) within 1 year after the affected source
becomes subject to the provisions of this subpart or by one year after
publication of the final rule in the Federal Register, whichever is
later. An affected source identified under Sec. 63.760(f)(7) or (9)
that plans to be an area source by three years after publication of the
final rule in the Federal Register, shall include in this notification
a brief, nonbinding description of a schedule for the action(s) that
are planned to achieve area source status.
* * * * *
(6) If there was a malfunction during the reporting period, the
Periodic Report specified in paragraph (e) of this section shall
include the number, duration, and a brief description for each type of
malfunction which occurred during the reporting period and which caused
or may have caused any applicable emission limitation to be exceeded.
The report must also include a description of actions taken by an owner
or operator during a malfunction of an affected source to minimize
emissions in accordance with Sec. 63.764(j), including actions taken
to correct a malfunction.
(7) [Reserved]
* * * * *
(c) * * *
(1) The initial notifications required under Sec. 63.9(b)(2) not
later than January 3, 2008. In addition to submitting your initial
notification to the addressees specified under Sec. 63.9(a), you must
also submit a copy of the initial notification to the EPA's Office of
Air Quality Planning and Standards. Send your notification via e-mail
to Oil and Gas [email protected] or via U.S. mail or other mail delivery
service to U.S. EPA, Sector Policies and Programs Division/Fuels and
Incineration Group (E143-01), Attn: Oil and Gas Project Leader,
Research Triangle Park, NC 27711.
* * * * *
(6) If there was a malfunction during the reporting period, the
Periodic Report specified in paragraph (e) of this section shall
include the number, duration, and
[[Page 52825]]
a brief description for each type of malfunction which occurred during
the reporting period and which caused or may have caused any applicable
emission limitation to be exceeded. The report must also include a
description of actions taken by an owner or operator during a
malfunction of an affected source to minimize emissions in accordance
with Sec. 63.764(j), including actions taken to correct a malfunction.
(7) * * *
(i) Documentation of the source's location relative to the nearest
UA plus offset and UC boundaries. This information shall include the
latitude and longitude of the affected source; whether the source is
located in an urban cluster with 10,000 people or more; the distance in
miles to the nearest urbanized area boundary if the source is not
located in an urban cluster with 10,000 people or more; and the name of
the nearest urban cluster with 10,000 people or more and nearest
urbanized area.
* * * * *
(d) * * *
(1) * * *
(i) The condenser design analysis documentation specified in Sec.
63.772(e)(4) of this subpart, if the owner or operator elects to
prepare a design analysis.
(ii) If the owner or operator is required 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. If the owner or
operator operates a combustion control device model tested under Sec.
63.772(h), an electronic copy of the performance test results shall be
submitted via e-mail to Oil and Gas [email protected].
* * * * *
(5) * * *
(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), (e)(3)(ii) or (f)(1).
* * * * *
(iv) For each carbon adsorber, the predetermined carbon replacement
schedule as required in Sec. 63.771(d)(5)(i).
* * * * *
(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 the HAP emission reduction of 95.0 percent,
or the BTEX limit in Sec. 63.765(b)(1)(iii), through process
modifications or a combination of process modifications and one or more
control devices.
* * * * *
(13) If the owner or operator installs a combustion control device
model tested under the procedures in Sec. 63.772(h), the data listed
under Sec. 63.772(h)(8).
(14) For each combustion control device model tested under Sec.
63.772(h), the information listed in paragraphs (d)(14)(i) through (vi)
of this section.
(i) Name, address and telephone number of the control device
manufacturer.
(ii) Control device model number.
(iii) Control device serial number.
(iv) Date of control device certification test.
(v) Manufacturer's HAP destruction efficiency rating.
(vi) Control device operating parameters, maximum allowable inlet
gas flowrate.
(e) * * *
(2) The owner or operator shall include the information specified
in paragraphs (e)(2)(i) through (xiii) of this section, as applicable.
* * * * *
(ii) * * *
(B) For each excursion caused when the 365-day average condenser
control efficiency is less than the value 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 the value specified in Sec. 63.773(d)(6)(iii), the report
must include the average values of the condenser control efficiency,
and the date and duration of the period that the excursion occurred.
* * * * *
(E) For each excursion caused when the maximum inlet gas flow rate
identified under Sec. 63.772(h) is exceeded, the report must include
the values of the inlet gas identified and the date and duration of the
period that the excursion occurred.
(F) For each excursion caused when visible emissions determined
under Sec. 63.772(i) exceed the maximum allowable duration, the report
must include the date and duration of the period that the excursion
occurred.
* * * * *
(xi) The results of any periodic test as required in Sec.
63.772(e)(3) conducted during the reporting period.
(xii) For each carbon adsorber used to meet the control device
requirements of Sec. 63.771(d)(1), records of each carbon replacement
that occurred during the reporting period.
(xiii) For combustion control device inspections conducted in
accordance with Sec. 63.773(b) the records specified in Sec.
63.774(i).
* * * * *
(g) Electronic reporting. (1) As of January 1, 2012 and within 60
days after the date of completing each performance test, as defined in
Sec. 63.2 and as required in this subpart, you must submit performance
test data, except opacity data, electronically to the EPA's Central
Data Exchange (CDX) by using the Electronic Reporting Tool (ERT) (see
http://www.epa.gov/ttn/chief/ert/ert tool.html/). Only data collected
using test methods compatible with ERT are subject to this requirement
to be submitted electronically into the EPA's WebFIRE database.
(2) All reports required by this subpart not subject to the
requirements in paragraphs (g)(1) of this section must be sent to the
Administrator at the appropriate address listed in Sec. 63.13. If
acceptable to both the Administrator and the owner or operator of a
source, these reports may be submitted on electronic media. The
Administrator retains the right to require submittal of reports subject
to paragraph (g)(1) of this section in paper format.
22. Appendix to subpart HH of part 63 is amended by revising Table
2 to read as follows:
Appendix to Subpart HH of Part 63--Tables
* * * * *
[[Page 52826]]
Table 2 to Subpart HH of Part 63--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)................... Yes.
Sec. 63.1(a)(7) through (a)(9).... No....................... Section reserved.
Sec. 63.1(a)(10).................. Yes.
Sec. 63.1(a)(11).................. Yes.
Sec. 63.1(a)(12).................. Yes.
Sec. 63.1(b)(1)................... No....................... Subpart HH specifies applicability.
Sec. 63.1(b)(2)................... No....................... Section reserved.
Sec. 63.1(b)(3)................... Yes.
Sec. 63.1(c)(1)................... No....................... Subpart HH specifies applicability.
Sec. 63.1(c)(2)................... Yes...................... Subpart HH exempts area sources from the
requirement to obtain a Title V permit unless
otherwise required by law as specified in Sec.
63.760(h).
Sec. 63.1(c)(3) and (c)(4)........ No....................... Section reserved.
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)(2).... Yes.
Sec. 63.4(a)(3) through (a)(5).... No....................... Section reserved.
Sec. 63.4(b)...................... Yes.
Sec. 63.4(c)...................... Yes.
Sec. 63.5(a)(1)................... Yes.
Sec. 63.5(a)(2)................... Yes.
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)................... No....................... Section reserved.
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.
Sec. 63.6(e)(1)(i)................ No....................... See Sec. 63.764(j) for general duty
requirement.
Sec. 63.6(e)(1)(ii)............... No.
Sec. 63.6(e)(1)(iii).............. Yes.
Sec. 63.6(e)(2)................... No....................... Section reserved.
Sec. 63.6(e)(3)................... No.
Sec. 63.6(f)(1)................... No.
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 contain opacity or visible
emission standards.
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.
[[Page 52827]]
Sec. 63.7(a)(1)................... Yes.
Sec. 63.7(a)(2)................... Yes...................... But the performance test results must be
submitted within 180 days after the compliance
date.
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)................... No.
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)................... No.
Sec. 63.8(c)(1)(i)................ No.......................
Sec. 63.8(c)(1)(ii)............... Yes.
Sec. 63.8(c)(1)(iii).............. Pending.
Sec. 63.8(c)(2)................... Yes.
Sec. 63.8(c)(3)................... Yes.
Sec. 63.8(c)(4)................... Yes.
Sec. 63.8(c)(4)(i)................ No....................... Subpart HH does not require continuous opacity
monitors.
Sec. 63.8(c)(4)(ii)............... Yes.
Sec. 63.8(c)(5) through (c)(8).... Yes.
Sec. 63.8(d)...................... Yes.
Sec. 63.8(d)(3)................... Yes...................... Except for last sentence, which refers to an
SSM plan. SSM plans are not required.
Sec. 63.8(e)...................... Yes...................... Subpart HH does not specifically require
continuous emissions monitor performance
evaluation, however, the Administrator can
request that one be conducted.
Sec. 63.8(f)(1) through (f)(5).... Yes.
Sec. 63.8(f)(6)................... Yes.
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...................... Existing sources are given 1 year (rather than
120 days) to submit this notification. Major
and area sources that meet Sec. 63.764(e) do
not have to submit initial notifications.
Sec. 63.9(b)(3)................... No....................... Section reserved.
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....................... Subpart HH does not have opacity or visible
emission standards.
Sec. 63.9(g)(1)................... Yes.
Sec. 63.9(g)(2)................... No....................... Subpart HH does not have opacity or visible
emission standards.
Sec. 63.9(g)(3)................... Yes.
Sec. 63.9(h)(1) through (h)(3).... Yes...................... Area sources located outside UA plus offset and
UC boundaries are not required to submit
notifications of compliance status.
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. 63.774(b)(1) requires sources to
maintain the most recent 12 months of data on-
site and allows offsite storage for the
remaining 4 years of data.
Sec. 63.10(b)(2).................. Yes.
Sec. 63.10(b)(2)(i)............... No.......................
Sec. 63.10(b)(2)(ii).............. No....................... See Sec. 63.774(g) for recordkeeping of
occurrence, duration, and actions taken during
malfunctions.
Sec. 63.10(b)(2)(iii)............. Yes.
Sec. 63.10(b)(2)(iv) through No.
(b)(2)(v).
Sec. 63.10(b)(2)(vi) through Yes.
(b)(2)(xiv).
[[Page 52828]]
Sec. 63.10(b)(3).................. Yes...................... Sec. 63.774(b)(1) requires sources to
maintain the most recent 12 months of data on-
site and allows offsite storage for the
remaining 4 years of data.
Sec. 63.10(c)(1).................. Yes.
Sec. 63.10(c)(2) through (c)(4)... No....................... Sections reserved.
Sec. 63.10(c)(5) through (8)(c)(8) Yes.
Sec. 63.10(c)(9).................. No....................... Section reserved.
Sec. 63.10(c)(10) through (11).... No....................... See Sec. 63.774(g) for recordkeeping of
malfunctions.
Sec. 63.10(c)(12) through (14).... Yes.
Sec. 63.10(c)(15)................. No.
Sec. 63.10(d)(1).................. Yes.
Sec. 63.10(d)(2).................. Yes...................... Area sources located outside UA plus offset and
UC boundaries do not have to submit
performance test reports.
Sec. 63.10(d)(3).................. Yes.
Sec. 63.10(d)(4).................. Yes.
Sec. 63.10(d)(5).................. No....................... See Sec. 63.775(b)(6) or (c)(6) for reporting
of malfunctions.
Sec. 63.10(e)(1).................. Yes...................... Area sources located outside UA plus offset and
UC boundaries are not required to submit
reports.
Sec. 63.10(e)(2).................. Yes...................... Area sources located outside UA plus offset and
UC boundaries are not required to submit
reports.
Sec. 63.10(e)(3)(i)............... Yes...................... Subpart HH requires major sources to submit
Periodic Reports semi-annually. Area sources
are required to submit Periodic Reports
annually. Area sources located outside UA plus
offset and UC boundaries are not required to
submit reports.
Sec. 63.10(e)(3)(i)(A)............ Yes.
Sec. 63.10(e)(3)(i)(B)............ Yes.
Sec. 63.10(e)(3)(i)(C)............ No....................... Section reserved.
Sec. 63.10(e)(3)(ii) through Yes.
(viii).
Sec. 63.10(f)..................... Yes.
Sec. 63.11(a) and (b)............. Yes.
Sec. 63.11(c), (d), and (e)....... 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.
Sec. 63.16........................ Yes.
----------------------------------------------------------------------------------------------------------------
Subpart HHH--[Amended]
23. Section 63.1270 is amended by:
a. Revising paragraph (a) introductory text;
b. Revising paragraph (a)(4);
c. Revising paragraphs (d)(1) and (d)(2); and
d. Adding paragraphs (d)(3), (4) and (5) to read as follows:
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
defined in Sec. 63.1271. Emissions for major source determination
purposes can be estimated using the maximum natural gas throughput
calculated in either paragraph (a)(1) or (2) of this section and
paragraphs (a)(3) and (4) of this section. As an alternative to
calculating the maximum natural gas throughput, the owner or operator
of a new or existing source may use the facility design maximum natural
gas throughput to estimate the maximum potential emissions. Other means
to determine the facility's major source status are allowed, provided
the information is documented and recorded to the Administrator's
satisfaction in accordance with Sec. 63.10(b)(3). A compressor station
that transports natural gas prior to the point of custody transfer or
to a natural gas processing plant (if present) is not considered a part
of the natural gas transmission and storage source category. A facility
that is determined to be an area source, but subsequently increases its
emissions or its potential to emit above the major source levels
(without obtaining and complying with other limitations that keep its
potential to emit HAP below major source levels), and becomes a major
source, 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.
* * * * *
(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. For estimating maximum potential emissions from glycol
dehydration units, the glycol circulation rate used in the calculation
shall be the unit's maximum rate under its physical and operational
design consistent with the definition of potential to emit in Sec.
63.2.
* * * * *
(d) * * *
(1) Except as specified in paragraphs (d)(3) through (5) of this
section, the owner or operator of an affected source, the construction
or reconstruction of which commenced before February 6,
[[Page 52829]]
1998, shall achieve compliance with the 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) Except as specified in paragraphs (d)(3) through (5) of this
section, 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.
(3) Each affected small glycol dehydration unit, as defined in
Sec. 63.1271, located at a major source, that commenced construction
before August 23, 2011 must achieve compliance no later than 3 years
after the date of publication of the final rule in the Federal
Register, except as provided in Sec. 63.6(i).
(4) Each affected small glycol dehydration unit, as defined in
Sec. 63.1271, located at a major source, that commenced construction
on or after August 23, 2011 must achieve compliance immediately upon
initial startup or the date of publication of the final rule in the
Federal Register, whichever is later.
(5) Each large glycol dehydration unit, as defined in Sec.
63.1271, that has complied with the provisions of this subpart prior to
August 23, 2011 by reducing its benzene emissions to less than 0.9
megagrams per year must achieve compliance no later than 90 days after
the date of publication of the final rule in the Federal Register,
except as provided in Sec. 63.6(i).
* * * * *
24. Section 63.1271 is amended by:
a. Adding, in alphabetical order, new definitions for the terms
``affirmative defense,'' ``BTEX,'' ``flare,'' ``large glycol
dehydration units,'' ``small glycol dehydration units''; and
b. Revising the definitions for ``glycol dehydration unit baseline
operations'' and ``temperature monitoring device'' to read as follows:
Sec. 63.1271 Definitions.
* * * * *
Affirmative defense means, in the context of an enforcement
proceeding, a response or defense put forward by a defendant, regarding
which the defendant has the burden of proof, and the merits of which
are independently and objectively evaluated in a judicial or
administrative proceeding.
* * * * *
BTEX means benzene, toluene, ethyl benzene and xylene.
* * * * *
Flare means a thermal oxidation system using an open flame (i.e.,
without enclosure).
* * * * *
Glycol dehydration unit baseline operations means operations
representative of the large glycol dehydration unit operations as of
June 17, 1999 and the small glycol dehydration unit operations as of
August 23, 2011. 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.
* * * * *
Large glycol dehydration unit means a glycol dehydration unit with
an actual annual average natural gas flowrate equal to or greater than
283.0 thousand standard cubic meters per day and actual annual average
benzene emissions equal to or greater than 0.90 Mg/yr, determined
according to Sec. 63.1282(a).
* * * * *
Small glycol dehydration unit means a glycol dehydration unit,
located at a major source, with an actual annual average natural gas
flowrate less than 283.0 thousand standard cubic meters per day or
actual annual average benzene emissions less than 0.90 Mg/yr,
determined according to Sec. 63.1282(a).
Temperature monitoring device means an instrument used to monitor
temperature and having a minimum accuracy of 1 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.
* * * * *
25. Section 63.1272 is revised to read as follows:
Sec. 63.1272 Startups and shutdowns.
(a) The provisions set forth in this subpart shall apply at all
times.
(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 owner or operator must shut down the equipment to avoid
damage due to a contemporaneous startup or shutdown of the affected
source or a portion thereof.
(c) During startups and shutdowns, the owner or operator shall
implement measures to prevent or minimize excess emissions to the
maximum extent practical.
(d) In response to an action to enforce the standards set forth in
this subpart, you may assert an affirmative defense to a claim for
civil penalties for exceedances of such standards that are caused by
malfunction, as defined in Sec. 63.2. Appropriate penalties may be
assessed, however, if you fail to meet your burden of proving all the
requirements in the affirmative defense. The affirmative defense shall
not be available for claims for injunctive relief.
(1) To establish the affirmative defense in any action to enforce
such a limit, the owner or operator must timely meet the notification
requirements in paragraph (d)(2) of this section, and must prove by a
preponderance of evidence that:
(i) The excess emissions:
(A) Were caused by a sudden, infrequent, and unavoidable failure of
air pollution control and monitoring equipment, process equipment, or a
process to operate in a normal or usual manner; and
(B) Could not have been prevented through careful planning, proper
design or better operation and maintenance practices; and
(C) Did not stem from any activity or event that could have been
foreseen and avoided, or planned for; and
(D) Were not part of a recurring pattern indicative of inadequate
design, operation, or maintenance; and
(ii) Repairs were made as expeditiously as possible when the
applicable emission limitations were being exceeded. Off-shift and
overtime labor were used, to the extent practicable to make these
repairs; and
(iii) The frequency, amount and duration of the excess emissions
(including any bypass) were minimized
[[Page 52830]]
to the maximum extent practicable during periods of such emissions; and
(iv) If the excess emissions resulted from a bypass of control
equipment or a process, then the bypass was unavoidable to prevent loss
of life, personal injury, or severe property damage; and
(v) All possible steps were taken to minimize the impact of the
excess emissions on ambient air quality, the environment, and human
health; and
(vi) All emissions monitoring and control systems were kept in
operation if at all possible, consistent with safety and good air
pollution control practices; and
(vii) All of the actions in response to the excess emissions were
documented by properly signed, contemporaneous operating logs; and
(viii) At all times, the affected source was operated in a manner
consistent with good practices for minimizing emissions; and
(ix) A written root cause analysis has been prepared to determine,
correct, and eliminate the primary causes of the malfunction and the
excess emissions resulting from the malfunction event at issue. The
analysis shall also specify, using best monitoring methods and
engineering judgment, the amount of excess emissions that were the
result of the malfunction.
(2) Notification. The owner or operator of the affected source
experiencing an exceedance of its emission limit(s) during a
malfunction shall notify the Administrator by telephone or facsimile
transmission as soon as possible, but no later than two business days
after the initial occurrence of the malfunction, if it wishes to avail
itself of an affirmative defense to civil penalties for that
malfunction. The owner or operator seeking to assert an affirmative
defense shall also submit a written report to the Administrator within
45 days of the initial occurrence of the exceedance of the standard in
this subpart to demonstrate, with all necessary supporting
documentation, that it has met the requirements set forth in paragraph
(d)(1) of this section. The owner or operator may seek an extension of
this deadline for up to 30 additional days by submitting a written
request to the Administrator before the expiration of the 45 day
period. Until a request for an extension has been approved by the
Administrator, the owner or operator is subject to the requirement to
submit such report within 45 days of the initial occurrence of the
exceedance.
26. Section 63.1274 is amended by:
a. Revising paragraph (c) introductory text;
b. Removing and reserving paragraph (d);
c. Revising paragraph (g); and
d. Adding paragraph (h) to read as follows:
Sec. 63.1274 General standards.
* * * * *
(c) 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:
* * * * *
(d) [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, and a leak is detected, the
owner or operator shall take further action as required by the
applicable provisions of this subpart.
(h) At all times the owner or operator must operate and maintain
any affected source, including associated air pollution control
equipment and monitoring equipment, in a manner consistent with safety
and good air pollution control practices for minimizing emissions.
Determination of whether such operation and maintenance procedures are
being used will be based on information available to the Administrator
which may include, but is not limited to, monitoring results, review of
operation and maintenance procedures, review of operation and
maintenance records, and inspection of the source.
27. Section 63.1275 is amended by:
a. Revising paragraph (a);
b. Revising paragraph (b)(1);
c. Revising paragraph (c)(2); and
d. Revising paragraph (c)(3) to read as follows:
Sec. 63.1275 Glycol dehydration unit process vent standards.
(a) This section applies to each glycol dehydration unit subject to
this subpart that must be controlled for air emissions as specified in
paragraph (c)(1) of Sec. 63.1274.
(b) * * *
(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)(iii) of this section.
(i) The owner or operator of a large glycol dehydration unit, as
defined in Sec. 63.1271, 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) [Reserved]
(iii) You must limit BTEX emissions from each small glycol
dehydration unit, as defined in Sec. 63.1271, to the limit determined
in Equation 1 of this section. The limit must be met in accordance with
one of the alternatives specified in paragraphs (b)(i)(iii)(A) through
(D) of this section.
[GRAPHIC] [TIFF OMITTED] TP23AU11.007
[[Page 52831]]
Where:
ELBTEX = Unit-specific BTEX emission limit, megagrams per
year;
6.42 x 10-\5\ = BTEX emission limit, grams BTEX/standard
cubic meter -ppmv;
Throughput = Annual average daily natural gas throughput, standard
cubic meters per day
Ci,BTEX = BTEX concentration of the natural gas at the
inlet to the glycol dehydration unit, ppmv.
(A) Connect the process vent to a control device or 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(f).
(B) Meet the emissions limit through process modifications in
accordance with the requirements specified in Sec. 63.1281(e).
(C) Meet the emission limit for each small glycol dehydration unit
using a combination of process modifications and one or more control
devices through the requirements specified in paragraphs (b)(1)(iii)(A)
and (B) of this section.
(D) Demonstrate that the emissions limit is met through actual
uncontrolled operation of the small glycol dehydration unit. Document
operational parameters in accordance with the requirements specified in
Sec. 63.1281(e) and emissions in accordance with the requirements
specified in Sec. 63.1282(a)(3).
* * * * *
(c) * * *
(2) The owner or operator shall demonstrate, to the Administrator's
satisfaction, that the total HAP emissions to the atmosphere from the
large 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 paragraph (c)(3)(i) or (iii) through the
installation and operation of controls as specified in paragraph (b)(1)
of this section.
(i) For any large glycol dehydration unit, HAP emissions are
reduced by 95.0 percent or more.
(ii) [Reserved]
(iii) For each small glycol dehydration unit, BTEX emissions are
reduced to a level less than the limit calculated in paragraph
(b)(1)(iii) of this section.
28. Section 63.1281 is amended by:
a. Revising paragraph (c)(1);
b. Revising the heading of paragraph (d).
c. Adding paragraph (d) introductory text;
d. Revising paragraph (d)(1)(i) introductory text;
e. Revising paragraph (d)(1)(i)(C);
f. Revising paragraphs (d)(1)(ii) and (iii);
g. Revising paragraph (d)(4)(i);
h. Revising paragraph (d)(5)(i);
i. Revising paragraph (e)(2);
j. Revising paragraph (e)(3) introductory text;
k. Revising paragraph (e)(3)(ii); and
l. Adding paragraph (f) to read as follows:
Sec. 63.1281 Control equipment requirements.
* * * * *
(c) * * *
(1) The closed-vent system shall route all gases, vapors, and fumes
emitted from the material in an emissions unit to a control device that
meets the requirements specified in paragraph (d) of this section.
* * * * *
(d) Control device requirements for sources except small glycol
dehydration units. Owners and operators of small glycol dehydration
units shall comply with the control requirements in paragraph (f) of
this section.
(1) * * *
(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:
* * * * *
(C) For a control device that can demonstrate a uniform combustion
zone temperature during the performance test conducted under Sec.
63.1282(d), operates at a minimum temperature of 760 [deg]C.
* * * * *
(ii) A vapor recovery device (e.g., carbon adsorption system or
condenser) or other non-destructive 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, as defined in Sec. 63.1271, that is designed and
operated in accordance with the requirements of Sec. 63.11(b).
* * * * *
(4) * * *
(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. An owner or operator
may vent more than one unit to a control device used to comply with
this subpart.
* * * * *
(5) * * *
(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. Records identifying
the schedule for replacement and records of each carbon replacement
shall be maintained as required in Sec. 63.1284(b)(7)(ix). The
schedule for replacement shall be submitted with the Notification of
Compliance Status Report as specified in Sec. 63.1285(d)(4)(iv). Each
carbon replacement must be reported in the Periodic Reports as
specified in Sec. 63.1285(e)(2)(xi).
* * * * *
(e) * * *
(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, or BTEX limit determined in Sec.
63.1275(b)(1)(iii), as applicable, 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 emission 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 or, if applicable, the BTEX limit
determined in Sec. 63.1275(b)(1)(iii) for the small 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
emission reduction due to process modifications.
(3) The owner or operator that achieves a 95.0 percent HAP emission
reduction or meets the BTEX limit
[[Page 52832]]
determined in Sec. 63.1275(b)(1)(iii), as applicable, 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 or meets the BTEX limit determined in Sec.
63.1275(b)(1)(iii), as applicable, 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.
* * * * *
(ii) The owner or operator shall comply with the control device
requirements specified in paragraph (d) or (f) of this section, as
applicable, except that the emission reduction or limit achieved shall
be the emission reduction or limit specified for the control device(s)
in paragraph (e)(2) of this section.
(f) Control device requirements for small glycol dehydration units.
(1) The control device used to meet BTEX the emission limit calculated
in Sec. 63.1275(b)(1)(iii) shall be one of the control devices
specified in paragraphs (f)(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 to reduce the mass content of BTEX in the gases
vented to the device as determined in accordance with the requirements
of Sec. 63.1282(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; or
(ii) A vapor recovery device (e.g., carbon adsorption system or
condenser) or other non-destructive control device that is designed and
operated to reduce the mass content of BTEX in the gases vented to the
device as determined in accordance with the requirements of Sec.
63.1282(d); or
(iii) A flare, as defined in Sec. 63.1271, that is designed and
operated in accordance with the requirements of Sec. 63.11(b).
(2) The owner or operator shall operate each control device in
accordance with the requirements specified in paragraphs (f)(2)(i) and
(ii) of this section.
(i) Each control device used to comply with this subpart shall be
operating at all times. 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. 63.1283(d), the owner or operator shall
demonstrate compliance according to the requirements of either Sec.
63.1282(e) or (h).
(3) For each carbon adsorption system used as a control device to
meet the requirements of paragraph (f)(1) of this section, the owner or
operator shall manage the carbon as required under (d)(5)(i) and (ii)
of this section.
29. Section 63.1282 is amended by:
a. Revising paragraph (a) introductory text;
b. Revising paragraph (a)(1)(ii);
c. Revising paragraph (a)(2);
d. Adding paragraph (c);
e. Revising paragraph (d) introductory text;
f. Revising paragraphs (d)(1)(i) through (v);
g. Revising paragraph (d)(2);
h. Revising paragraph (d)(3) introductory text;
i. Revising paragraph (d)(3)(i)(B);
j. Revising paragraph (d)(3)(iv)(C)(1);
k. Adding paragraphs (d)(3)(v) and (vi);
l. Revising paragraph (d)(4) introductory text;
m. Revising paragraph (d)(4)(i);
n. Revising paragraph (d)(5);
o. Revising paragraph (e) introductory text;
p. Revising paragraphs (e)(2) and (e)(3);
q. Adding paragraphs (e)(4) through (e)(6);
r. Revising paragraph (f) introductory text;
s. Revising paragraph (f)(1);
t. Revising paragraph (f)(2) introductory text;
u. Revising paragraph (f)(2)(iii);
v. Revising paragraph (f)(3); and
w. Adding paragraphs (g) and (h) to read as follows:
Sec. 63.1282 Test methods, compliance procedures, and compliance
demonstrations.
(a) Determination of glycol dehydration unit flowrate, benzene
emissions, or BTEX emissions. The procedures of this paragraph shall be
used by an owner or operator to determine glycol dehydration unit
natural gas flowrate, benzene emissions, or BTEX emissions.
(1) * * *
(ii) The owner or operator shall document, to the Administrator's
satisfaction, the actual annual average natural gas flowrate to the
glycol dehydration unit.
(2) The determination of actual average benzene or BTEX 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 or
BTEX emissions using the model GRI-GLYCalc\TM\, Version 3.0 or higher,
and the procedures presented in the associated GRI-GLYCalc\TM\
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 or BTEX 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.
* * * * *
(c) Test procedures and compliance demonstrations for small glycol
dehydration units. This paragraph applies to the test procedures for
small dehydration units.
(1) If the owner or operator is using a control device to comply
with the emission limit in Sec. 63.1275(b)(1)(iii), the requirements
of paragraph (d) of this section apply. Compliance is demonstrated
using the methods specified in paragraph (e) of this section.
(2) If no control device is used to comply with the emission limit
in Sec. 63.1275(b)(1)(iii), the owner or operator must determine the
glycol dehydration unit BTEX emissions as specified in paragraphs
(c)(2)(i) through (iii) of this section. Compliance is demonstrated if
the BTEX emissions determined as specified in paragraphs (c)(2)(i)
through (iii) are less than the emission limit calculated using the
equation in Sec. 63.1275(b)(1)(iii).
(i) Method 1 or 1A, 40 CFR part 60, appendix A, as appropriate,
shall be used for selection of the sampling sites at the outlet of the
glycol dehydration unit process vent. Any references to particulate
mentioned in Methods 1 and 1A do not apply to this section.
(ii) The gas volumetric flowrate shall be determined using Method
2, 2A, 2C, or 2D, 40 CFR part 60, appendix A, as appropriate.
(iii) The BTEX emissions from the outlet of the glycol dehydration
unit
[[Page 52833]]
process vent shall be determined using the procedures specified in
paragraph (d)(3)(v) of this section. As an alternative, the mass rate
of BTEX at the outlet of the glycol dehydration unit process vent may
be calculated using the model GRI-GLYCalc\TM\, Version 3.0 or higher,
and the procedures presented in the associated GRI-GLYCalc\TM\
Technical Reference Manual. Inputs to the model shall be representative
of actual operating conditions of the glycol dehydration unit and shall
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). When the
BTEX mass rate is calculated for glycol dehydration units using the
model GRI-GLYCalc\TM\, all BTEX measured by Method 18, 40 CFR part 60,
appendix A, shall be summed.
(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), (e)(3)(ii), or (f)(1)
using a performance test as specified in paragraph (d)(3) of this
section. Owners or operators using a condenser have the option to use 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.
As an alternative to conducting a performance test under this section
for combustion control devices, a control device that can be
demonstrated to meet the performance requirements of Sec.
63.1281(d)(1), (e)(3)(ii), or (f)(1) through a performance test
conducted by the manufacturer, as specified in paragraph (g) of this
section, can be used.
(1) * * *
(i) Except as specified in paragraph (d)(2) of this section, a
flare, as defined in Sec. 63.1271, that is designed and operated in
accordance with Sec. 63.11(b);
(ii) Except for control devices used for small glycol dehydration
units, a boiler or process heater with a design heat input capacity of
44 megawatts or greater;
(iii) Except for control devices used for small glycol dehydration
units, a boiler or process heater into which the vent stream is
introduced with the primary fuel or is used as the primary fuel;
(iv) Except for control devices used for small glycol dehydration
units, 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) Except for control devices used for small glycol dehydration
units, 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.
* * * * *
(2) An owner or operator shall design and operate each flare, as
defined in Sec. 63.1271, in accordance with the requirements specified
in Sec. 63.11(b) and the compliance determination shall be conducted
using Method 22 of 40 CFR part 60, appendix A, to determine visible
emissions.
(3) For a performance test conducted to demonstrate that a control
device meets the requirements of Sec. 63.1281(d)(1), (e)(3)(ii), or
(f)(1) the owner or operator shall use the test methods and procedures
specified in paragraphs (d)(3)(i) through (v) of this section. The
initial and periodic performance tests shall be conducted according to
the schedule specified in paragraph (d)(3)(vi) of this section.
(i) * * *
(B) To determine compliance with the enclosed combustion device
total HAP concentration limit specified in Sec. 63.1281(d)(1)(i)(B),
or the BTEX emission limit specified in Sec. 63.1275(b)(1)(iii), the
sampling site shall be located at the outlet of the combustion device.
* * * * *
(iv) * * *
(C) * * *
(1) The emission rate correction factor for excess air, integrated
sampling and analysis procedures of Method 3A or 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.
* * * * *
(v) To determine compliance with the BTEX emission limit specified
in Sec. 63.1281(f)(1) the owner or operator shall use one of the
following methods: Method 18, 40 CFR part 60, appendix A; ASTM D6420-99
(2004), as specified in Sec. 63.772(a)(1)(ii); or any other method or
data that have been validated according to the applicable procedures in
Method 301, 40 CFR part 63, appendix A. The following procedures shall
be used to calculate BTEX emissions:
(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 BTEX (Eo) shall be computed using
the equations and procedures specified in paragraphs (d)(3)(v)(B)(1)
and (2) of this section.
(1) The following equation shall be used:
[GRAPHIC] [TIFF OMITTED] TP23AU11.004
Where:
Eo = Mass rate of BTEX at the outlet of the control
device, dry basis, kilogram per hour.
Coj = Concentration of sample component j of the gas
stream at the outlet of the control device, dry basis, parts per
million by volume.
Moj = Molecular weight of sample component j of the gas
stream at the outlet of the control device, gram/gram-mole.
Qo = Flowrate of gas stream at the outlet of the control
device, dry standard cubic meter per minute.
K2 = Constant, 2.494 x 10-6 (parts per
million) (gram-mole per standard cubic meter) (kilogram/gram)
(minute/hour), where standard temperature (gram-mole per standard
cubic meter) is 20 degrees C.
n = Number of components in sample.
(2) When the BTEX mass rate is calculated, only BTEX compounds
measured by Method 18, 40 CFR part 60, appendix A, or ASTM D6420-99
(2004) as specified in Sec. 63.772(a)(1)(ii), shall be summed using
the equations in paragraph (d)(3)(v)(B)(1) of this section.
(vi) The owner or operator shall conduct performance tests
according to the schedule specified in paragraphs (d)(3)(vi)(A) and (B)
of this section.
(A) An initial performance test shall be conducted within 180 days
after the compliance date that is specified for each affected source in
Sec. 63.1270(d)(3) and (4) except that the initial performance test
for existing combustion control devices at existing major sources shall
be conducted no later than 3 years after the date of publication of the
final rule in the Federal Register. If the owner or operator of an
existing combustion
[[Page 52834]]
control device at an existing major source chooses to replace such
device with a control device whose model is tested under Sec.
63.1282(g), then the newly installed device shall comply with all
provisions of this subpart no later than 3 years after the date of
publication of the final rule in the Federal Register. The performance
test results shall be submitted in the Notification of Compliance
Status Report as required in Sec. 63.1285(d)(1)(ii).
(B) Periodic performance tests shall be conducted for all control
devices required to conduct initial performance tests except as
specified in paragraphs (e)(3)(vi)(B)(1) and (2) of this section. The
first periodic performance test shall be conducted no later than 60
months after the initial performance test required in paragraph
(d)(3)(vi)(A) of this section. Subsequent periodic performance tests
shall be conducted at intervals no longer than 60 months following the
previous periodic performance test or whenever a source desires to
establish a new operating limit. The periodic performance test results
must be submitted in the next Periodic Report as specified in Sec.
63.1285(e)(2)(x). Combustion control devices meeting the criteria in
either paragraph (e)(3)(vi)(B)(1) or (2) of this section are not
required to conduct periodic performance tests.
(1) A control device whose model is tested under, and meets the
criteria of, Sec. 63.1282(g), or
(2) A combustion control device tested under Sec. 63.1282(d) that
meets the outlet TOC or HAP performance level specified in Sec.
63.1281(d)(1)(i)(B) and that establishes a correlation between firebox
or combustion chamber temperature and the TOC or HAP performance level.
* * * * *
(4) For a condenser design analysis conducted to meet the
requirements of Sec. 63.1281(d)(1), (e)(3)(ii), or (f)(1), 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 condenser design analysis shall include an analysis of 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 condenser design analysis, an owner or operator may elect to use
the procedures specified in paragraph (d)(5) of this section.
* * * * *
(5) As an alternative to the procedures in paragraph (d)(4)(i) 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-GLYCalc\TM\, Version 3.0 or higher, to
generate a condenser performance curve.
(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), (e)(3)(ii), and (f)(1). Compliance shall be demonstrated
using the requirements in paragraphs (e)(1) through (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)(1)(ii), (e)(3)(ii), or (f)(1) 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.
* * * * *
(2) The owner or operator shall calculate the daily average of the
applicable monitored parameter in accordance with Sec. 63.1283(d)(4)
except that the inlet gas flowrate to the control device shall not be
averaged.
(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. For inlet gas flowrate, compliance with the operating
parameter limit is achieved when the value is equal to or less than the
value established under Sec. 63.1282(g).
(4) Except for periods of monitoring system malfunctions, repairs
associated with monitoring system malfunctions, and required monitoring
system quality assurance or quality control activities (including, as
applicable, system accuracy audits and required zero and span
adjustments), the CMS required in Sec. 63.1283(d) must be operated at
all times the affected source is operating. A monitoring system
malfunction is any sudden, infrequent, not reasonably preventable
failure of the monitoring system to provide valid data. Monitoring
system failures that are caused in part by poor maintenance or careless
operation are not malfunctions. Monitoring system repairs are required
to be completed in response to monitoring system malfunctions and to
return the monitoring system to operation as expeditiously as
practicable.
(5) Data recorded during monitoring system malfunctions, repairs
associated with monitoring system malfunctions, or required monitoring
system quality assurance or control activities may not be used in
calculations used to report emissions or operating levels. All the data
collected during all other required data collection periods must be
used in assessing the operation of the control device and associated
control system.
(6) Except for periods of monitoring system malfunctions, repairs
associated with monitoring system malfunctions, and required quality
monitoring system quality assurance or quality control activities
(including, as applicable, system accuracy audits and required zero and
span adjustments), failure to collect required data is a deviation of
the monitoring requirements.
(f) Compliance demonstration with percent reduction or emission
limit performance requirements--condensers. This paragraph applies to
the demonstration of compliance with the performance requirements
specified in Sec. 63.1281(d)(1)(ii), (e)(3) or (f)(1) 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). For sources required to meet the BTEX limit in
accordance with Sec. 63.1281(e) or (f)(1) the owner or operator shall
identify the minimum percent reduction necessary to meet the BTEX
limit.
(2) Compliance with the percent reduction requirement in Sec.
63.1281(d)(1)(ii), (e)(3), or (f)(1) shall be demonstrated by the
procedures in paragraphs (f)(2)(i) through (iii) of this section.
* * * * *
[[Page 52835]]
(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, or BTEX, emission reduction, as
appropriate, from the condenser efficiencies as 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. 63.1281(e), the
30-day average HAP emission, or BTEX, emission reduction, shall be
calculated using the emission reduction achieved through process
modifications and the condenser efficiency as 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(d), an
owner or operator of a facility that stores natural gas that has less
than 30 days of data for determining the average HAP, or BTEX, emission
reduction, as appropriate, shall calculate the cumulative average at
the end of the withdrawal season, each season, until 30 days of
condenser operating data are 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, or BTEX, emission reduction, as
appropriate, 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(d), for an
owner or operator that has less than 30 days of data for determining
the average HAP, or BTEX, emission reduction, as appropriate,
compliance is achieved if the average HAP, or BTEX, emission reduction,
as appropriate, calculated in paragraph (f)(2)(iii)(A) of this section
is equal to or greater than 95.0 percent.
* * * * *
(3) Compliance is achieved based on the applicable criteria in
paragraphs (f)(3)(i) or (ii) of this section.
(i) For sources meeting the HAP emission reduction specified in
Sec. 63.1281(d)(1)(ii) or (e)(3) if the average HAP emission reduction
calculated in paragraph (f)(2)(iii) of this section is equal to or
greater than 95.0 percent.
(ii) For sources required to meet the BTEX limit under Sec.
63.1281(e)(3) or (f)(1), compliance is achieved if the average BTEX
emission reduction calculated in paragraph (f)(2)(iii) of this section
is equal to or greater than the minimum percent reduction identified in
paragraph (f)(1) of this section.
* * * * *
(g) Performance testing for combustion control devices--
manufacturers' performance test. (1) This paragraph applies to the
performance testing of a combustion control device conducted by the
device manufacturer. The manufacturer shall demonstrate that a specific
model of control device achieves the performance requirements in (g)(7)
of this section by conducting a performance test as specified in
paragraphs (g)(2) through (6) of this section.
(2) Performance testing shall consist of three one-hour (or longer)
test runs for each of the four following firing rate settings making a
total of 12 test runs per test. Propene (propylene) gas shall be used
for the testing fuel. All fuel analyses shall be performed by an
independent third-party laboratory (not affiliated with the control
device manufacturer or fuel supplier).
(i) 90-100 percent of maximum design rate (fixed rate).
(ii) 70-100-70 percent (ramp up, ramp down). Begin the test at 70
percent of the maximum design rate. Within the first 5 minutes, ramp
the firing rate to 100 percent of the maximum design rate. Hold at 100
percent for 5 minutes. In the 10-15 minute time range, ramp back down
to 70 percent of the maximum design rate. Repeat three more times for a
total of 60 minutes of sampling.
(iii) 30-70-30 percent (ramp up, ramp down). Begin the test at 30
percent of the maximum design rate. Within the first 5 minutes, ramp
the firing rate to 70 percent of the maximum design rate. Hold at 70
percent for 5 minutes. In the 10-15 minute time range, ramp back down
to 30 percent of the maximum design rate. Repeat three more times for a
total of 60 minutes of sampling.
(iv) 0-30-0 percent (ramp up, ramp down). Begin the test at 0
percent of the maximum design rate. Within the first 5 minutes, ramp
the firing rate to 100 percent of the maximum design rate. Hold at 30
percent for 5 minutes. In the 10-15 minute time range, ramp back down
to 0 percent of the maximum design rate. Repeat three more times for a
total of 60 minutes of sampling.
(3) All models employing multiple enclosures shall be tested
simultaneously and with all burners operational. Results shall be
reported for the each enclosure individually and for the average of the
emissions from all interconnected combustion enclosures/chambers.
Control device operating data shall be collected continuously
throughout the performance test using an electronic Data Acquisition
System and strip chart. Data shall be submitted with the test report in
accordance with paragraph (g)(8)(iii) of this section.
(4) Inlet testing shall be conducted as specified in paragraphs
(g)(4)(i) through (iii) of this section.
(i) The fuel flow metering system shall be located in accordance
with Method 2A, 40 CFR part 60, appendix A-1, (or other approved
procedure) to measure fuel flow rate at the control device inlet
location. The fitting for filling fuel sample containers shall be
located a minimum of 8 pipe diameters upstream of any inlet fuel flow
monitoring meter.
(ii) Inlet flow rate shall be determined using Method 2A, 40 CFR
part 60, appendix A-1. Record the start and stop reading for each 60-
minute THC test. Record the gas pressure and temperature at 5-minute
intervals throughout each 60-minute THC test.
(iii) Inlet fuel sampling shall be conducted in accordance with the
criteria in paragraphs (g)(4)(iii)(A) and (B) of this section.
(A) At the inlet fuel sampling location, securely connect a
Silonite-coated stainless steel evacuated canister fitted with a flow
controller sufficient to fill the canister over a 1 hour period.
Filling shall be conducted as specified in the following:
(1) Open the canister sampling valve at the beginning of the total
hydrocarbon (THC) test, and close the canister at the end of the THC
test.
(2) Fill one canister for each THC test run.
(3) Label the canisters individually and record on a chain of
custody form.
(B) Each fuel sample shall be analyzed using the following methods.
The results shall be included in the test report.
(1) Hydrocarbon compounds containing between one and five atoms of
carbon plus benzene using ASTM D1945-03.
(2) Hydrogen (H2), carbon monoxide (CO), carbon dioxide
(CO2), nitrogen (N2), oxygen (O2)
using ASTM D1945-03.
(3) Carbonyl sulfide, carbon disulfide plus mercaptans using ASTM
D5504.
(4) Higher heating value using ASTM D3588-98 or ASTM D4891-89.
(5) Outlet testing shall be conducted in accordance with the
criteria in paragraphs (g)(5)(i) through (v) of this section.
(i) Sampling and flowrate measured in accordance with the
following:
(A) The outlet sampling location shall be a minimum of 4 equivalent
stack diameters downstream from the highest peak flame or any other
flow disturbance, and a minimum of one equivalent stack diameter
upstream of
[[Page 52836]]
the exit or any other flow disturbance. A minimum of two sample ports
shall be used.
(B) Flow rate shall be measured using Method 1, 40 CFR part 60,
Appendix 1, for determining flow measurement traverse point location;
and Method 2, 40 CFR part 60, Appendix 1, shall be used to measure duct
velocity. If low flow conditions are encountered (i.e., velocity
pressure differentials less than 0.05 inches of water) during the
performance test, a more sensitive manometer shall be used to obtain an
accurate flow profile.
(ii) Molecular weight shall be determined as specified in
paragraphs (g)(4)(iii)(B), and (g)(5)(ii)(A) and (B) of this section.
(A) An integrated bag sample shall be collected during the Method
4, 40 CFR part 60, Appendix A, moisture test. Analyze the bag sample
using a gas chromatograph-thermal conductivity detector (GC-TCD)
analysis meeting the following criteria:
(1) Collect the integrated sample throughout the entire test, and
collect representative volumes from each traverse location.
(2) The sampling line shall be purged with stack gas before opening
the valve and beginning to fill the bag.
(3) The bag contents shall be kneaded or otherwise vigorously mixed
prior to the GC analysis.
(4) The GC-TCD calibration procedure in Method 3C, 40 CFR part 60,
Appendix A, shall be modified by using EPAAlt-045 as follows: For the
initial calibration, triplicate injections of any single concentration
must agree within 5 percent of their mean to be valid. The calibration
response factor for a single concentration re-check must be within 10
percent of the original calibration response factor for that
concentration. If this criterion is not met, the initial calibration
using at least three concentration levels shall be repeated.
(B) Report the molecular weight of: O2, CO2,
methane (CH4), and N2 and include in the test report
submitted under Sec. 63.775(d)(iii). Moisture shall be determined
using Method 4, 40 CFR part 60, Appendix A. Traverse both ports with
the Method 4, 40 CFR part 60, Appendix A, sampling train during each
test run. Ambient air shall not be introduced into the Method 3C, 40
CFR part 60, Appendix A, integrated bag sample during the port change.
(iv) Carbon monoxide shall be determined using Method 10, 40 CFR
part 60, Appendix A. The test shall be run at the same time and with
the sample points used for the EPA Method 25A, 40 CFR part 60, Appendix
A, testing. An instrument range of 0-10 per million by volume-dry
(ppmvd) shall be used.
(v) Visible emissions shall be determined using Method 22, 40 CFR
part 60, Appendix A. The test shall be performed continuously during
each test run. A digital color photograph of the exhaust point, taken
from the position of the observer and annotated with date and time,
will be taken once per test run and the four photos included in the
test report.
(6) Total hydrocarbons (THC) shall be determined as specified by
the following criteria:
(i) Conduct THC sampling using Method 25A, 40 CFR part 60, Appendix
A, except the option for locating the probe in the center 10 percent of
the stack shall not be allowed. The THC probe must be traversed to 16.7
percent, 50 percent, and 83.3 percent of the stack diameter during the
testing.
(ii) A valid test shall consist of three Method 25A, 40 CFR part
60, Appendix A, tests, each no less than 60 minutes in duration.
(iii) A 0-10 parts per million by volume-wet (ppmvw) (as propane)
measurement range is preferred; as an alternative a 0-30 ppmvw (as
carbon) measurement range may be used.
(iv) Calibration gases will be propane in air and be certified
through EPA Protocol 1--``EPA Traceability Protocol for Assay and
Certification of Gaseous Calibration Standards,'' September 1997, as
amended August 25, 1999, EPA-600/R-97/121 (or more recent if updated
since 1999).
(v) THC measurements shall be reported in terms of ppmvw as
propane.
(vi) THC results shall be corrected to 3 percent CO2, as
measured by Method 3C, 40 CFR part 60, Appendix A.
(vii) Subtraction of methane/ethane from the THC data is not
allowed in determining results.
(7) Performance test criteria:
(i) The control device model tested must meet the criteria in
paragraphs (g)(7)(i)(A) through (C) of this section:
(A) Method 22, 40 CFR part 60, Appendix A, results under paragraph
(g)(5)(v) of this section with no indication of visible emissions, and
(B) Average Method 25A, 40 CFR part 60, Appendix A, results under
paragraph (g)(6) of this section equal to or less than 10.0 ppmvw THC
as propane corrected to 3.0 percent CO2, and
(C) Average CO emissions determined under paragraph (g)(5)(iv) of
this section equal to or less than 10 parts ppmvd, corrected to 3.0
percent CO2.
(ii) The manufacturer shall determine a maximum inlet gas flow rate
which shall not be exceeded for each control device model to achieve
the criteria in paragraph (g)(7)(i) of this section.
(iii) A control device meeting the criteria in paragraph
(g)(7)(i)(A) through (C) of this section will have demonstrated a
destruction efficiency of 98.0 percent for HAP regulated under this
subpart.
(8) The owner or operator of a combustion control device model
tested under this section shall submit the information listed in
paragraphs (g)(8)(i) through (iii) in the test report required under
Sec. 63.775(d)(1)(iii).
(i) Full schematic of the control device and dimensions of the
device components.
(ii) Design net heating value (minimum and maximum) of the device.
(iii) Test fuel gas flow range (in both mass and volume). Include
the minimum and maximum allowable inlet gas flow rate.
(iv) Air/stream injection/assist ranges, if used.
(v) The test parameter ranges listed in paragraphs (g)(8)(v)(A)
through (O) of this section, as applicable for the tested model.
(A) Fuel gas delivery pressure and temperature.
(B) Fuel gas moisture range.
(C) Purge gas usage range.
(D) Condensate (liquid fuel) separation range.
(E) Combustion zone temperature range. This is required for all
devices that measure this parameter.
(F) Excess combustion air range.
(G) Flame arrestor(s).
(H) Burner manifold pressure.
(I) Pilot flame sensor.
(J) Pilot flame design fuel and fuel usage.
(K) Tip velocity range.
(L) Momentum flux ratio.
(M) Exit temperature range.
(N) Exit flow rate.
(O) Wind velocity and direction.
(vi) The test report shall include all calibration quality
assurance/quality control data, calibration gas values, gas cylinder
certification, and strip charts annotated with test times and
calibration values.
(h) Compliance demonstration for combustion control devices--
manufacturers' performance test. This paragraph applies to the
demonstration of compliance for a combustion control device tested
under the provisions in paragraph (g) of this section. Owners or
operators shall demonstrate that a control device achieves the
performance requirements of Sec. 63.1281(d)(1), (e)(3)(ii) or (f)(1),
by installing a device tested under paragraph (g) of this section and
complying with the following criteria:
[[Page 52837]]
(1) The inlet gas flow rate shall meet the range specified by the
manufacturer. Flow rate shall be measured as specified in Sec.
63.1283(d)(3)(i)(H)(1).
(2) A pilot flame shall be present at all times of operation. The
pilot flame shall be monitored in accordance with Sec.
63.1283(d)(3)(i)(H)(2).
(3) Devices shall be operated with no visible emissions, except for
periods not to exceed a total of 5 minutes during any 2 consecutive
hours. A visible emissions test using Method 22, 40 CFR part 60,
Appendix A, shall be performed monthly. The observation period shall be
2 hours and shall be used according to Method 22.
(4) Compliance with the operating parameter limit is achieved when
the following criteria are met:
(i) The inlet gas flow rate monitored under paragraph (h)(1) of
this section is equal to or below the maximum established by the
manufacturer; and
(ii) The pilot flame is present at all times; and
(iii) During the visible emissions test performed under paragraph
(h)(3) of this section the duration of visible emissions does not
exceed a total of 5 minutes during the observation period. Devices
failing the visible emissions test shall follow the requirements in
paragraphs (h)(4)(iii)(A) and (B) of this section.
(A) Following the first failure, the fuel nozzle(s) and burner
tubes shall be replaced.
(B) If, following replacement of the fuel nozzle(s) and burner
tubes as specified in paragraph (h)(4)(iii)(A), the visible emissions
test is not passed in the next scheduled test, either a performance
test shall be performed under paragraph (d) of this section, or the
device shall be replaced with another control device whose model was
tested, and meets, the requirements in paragraph (g) of this section.
30. Section 63.1283 is amended by:
a. Adding paragraph (b);
b. Revising paragraph (d)(1) introductory text;
c. Revising paragraph (d)(1)(ii) and adding paragraphs (d)(1)(iii)
and (iv);
d. Revising paragraph (d)(2)(i) and (d)(2)(ii);
e. Revising paragraphs (d)(3)(i)(A) and (B);
f. Revising paragraphs (d)(3)(i)(D) and (E);
g. Revising paragraphs (d)(3)(i)(F)(1) and (2);
h. Revising paragraph (d)(3)(i)(G);
i. Adding paragraph (d)(3)(i)(H);
j. Revising paragraph (d)(4);
k. Revising paragraph (d)(5)(i);
l. Revising paragraphs (d)(5)(ii)(A) through (C);
m. Revising paragraph (d)(6) introductory text;
n. Revising paragraph (d)(6)(ii);
o. Adding paragraph (d)(6)(v);
p. Revising paragraph (d)(8)(i)(A); and
q. Revising paragraph (d)(8)(ii) to read as follows:
Sec. 63.1283 Inspection and monitoring requirements.
* * * * *
(b) The owner or operator of a control device whose model was
tested under 63.1282(g) shall develop an inspection and maintenance
plan for each control device. At a minimum, the plan shall contain the
control device manufacturer's recommendations for ensuring proper
operation of the device. Semi-annual inspections shall be conducted for
each control device with maintenance and replacement of control device
components made in accordance with the plan.
* * * * *
(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. Owners or operators that install
and operate a flare in accordance with Sec. 63.1281(d)(1)(iii) or
(f)(1)(iii) are exempt from the requirements of paragraphs (d)(4) and
(5) 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.
63.1281(d), (e)(3), or (f)(1). Each continuous parameter monitoring
system shall meet the following specifications and requirements:
* * * * *
(ii) A site-specific monitoring plan must be prepared that
addresses the monitoring system design, data collection, and the
quality assurance and quality control elements outlined in paragraph
(d) of this section and in Sec. 63.8(d). Each CPMS must be installed,
calibrated, operated, and maintained in accordance with the procedures
in your approved site-specific monitoring plan. Using the process
described in Sec. 63.8(f)(4), you may request approval of monitoring
system quality assurance and quality control procedures alternative to
those specified in paragraphs (d)(1)(ii)(A) through (E) of this section
in your site-specific monitoring plan.
(A) The performance criteria and design specifications for the
monitoring system equipment, including the sample interface, detector
signal analyzer, and data acquisition and calculations;
(B) Sampling interface (e.g., thermocouple) location such that the
monitoring system will provide representative measurements;
(C) Equipment performance checks, system accuracy audits, or other
audit procedures;
(D) Ongoing operation and maintenance procedures in accordance with
provisions in Sec. 63.8(c)(1) and (c)(3); and
(E) Ongoing reporting and recordkeeping procedures in accordance
with provisions in Sec. 63.10(c), (e)(1), and (e)(2)(i).
(iii) The owner or operator must conduct the CPMS equipment
performance checks, system accuracy audits, or other audit procedures
specified in the site-specific monitoring plan at least once every 12
months.
(iv) The owner or operator must conduct a performance evaluation of
each CPMS in accordance with the site-specific monitoring plan.
(2) * * *
(i) Except for control devices for small glycol dehydration units,
a boiler or process heater in which all vent streams are introduced
with the primary fuel or are used as the primary fuel;
(ii) Except for control devices for small glycol dehydration units,
a boiler or process heater with a design heat input capacity equal to
or greater than 44 megawatts.
(3) * * *
(i) * * *
(A) For a thermal vapor incinerator that demonstrates during the
performance test conducted under Sec. 63.1282(d) that combustion zone
temperature is an accurate indicator of performance, a temperature
monitoring device equipped with a continuous recorder. The monitoring
device shall have a minimum accuracy of 1 percent of the
temperature being monitored in degrees C, or 2.5 degrees
C, whichever value is greater. The temperature sensor shall be
installed at a location representative of the combustion zone
temperature.
(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 1 percent of the temperatures being monitored in
degrees C, or 2.5 degrees 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
[[Page 52838]]
nearest feasible point to the catalyst bed outlet.
* * * * *
(D) For a boiler or process heater, a temperature monitoring device
equipped with a continuous recorder. The temperature monitoring device
shall have a minimum accuracy of 1 percent of the
temperature being monitored in degrees C, or 2.5 degrees
C, whichever value is greater. The temperature sensor shall be
installed at a location representative of the combustion zone
temperature.
(E) For a condenser, a temperature monitoring device equipped with
a continuous recorder. The temperature monitoring device shall have a
minimum accuracy of 1 percent of the temperature being
monitored in degrees C, or 2.8 degrees C, whichever value
is greater. The temperature sensor shall be installed at a location in
the exhaust vent stream from the condenser.
(F) * * *
(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 flow sensor must have a
measurement sensitivity of 5 percent of the flow rate or 10 cubic feet
per minute, whichever is greater. The mechanical connections for
leakage must be checked at least every month, and a visual inspection
must be performed at least every 3 months of all components of the flow
CPMS for physical and operational integrity and all electrical
connections for oxidation and galvanic corrosion if your flow CPMS is
not equipped with a redundant flow sensor; 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 1 percent of the temperature being monitored in degrees C, or
2.5 degrees 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) and shall be based on the total carbon working capacity
of the control device and source operating schedule.
(H) For a control device whose model is tested under Sec.
63.1282(g):
(1) A continuous monitoring system that measures gas flow rate at
the inlet to the control device. The monitoring instrument shall have
an accuracy of plus or minus 2 percent or better.
(2) A heat sensing monitoring device equipped with a continuous
recorder that indicates the continuous ignition of the pilot flame.
* * * * *
(4) Using the data recorded by the monitoring system, except for
inlet gas flowrate, the owner or operator must calculate the daily
average value for each monitored operating parameter for each operating
day. If the emissions unit operation is continuous, the operating day
is a 24-hour period. If the 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) * * *
(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), (e)(3)(ii), or (f)(1).
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), (e)(3)(ii), or (f)(1),
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 a condenser
design analysis or control device manufacturer's recommendations or a
combination of both.
(B) If the owner or operator uses a condenser 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), (e)(3)(ii), or (f)(1),
then the minimum operating parameter value or the maximum operating
parameter value shall be established based on the condenser design
analysis and may be supplemented by the condenser manufacturer's
recommendations.
(C) If the owner or operator operates a control device where the
performance test requirement was met under Sec. 63.1282(g) to
demonstrate that the control device achieves the applicable performance
requirements specified in Sec. 63.1281(d)(1), (e)(3)(ii) or (f)(1),
then the maximum inlet gas flow rate shall be established based on the
performance test and supplemented, as necessary, by the manufacturer
recommendations.
(ii) * * *
(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), (e)(3)(ii), or (f)(1), 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. 63.1282(d)(4)(i) to
demonstrate that the condenser achieves the applicable performance
requirements specified in Sec. 63.1281(d)(1), (e)(3)(ii), or (f)(1),
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 paragraph (d)(5)(ii)(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)(iv) of this
section, then a single excursion is determined to have occurred for the
control device for that operating day.
* * * * *
(ii) For sources meeting Sec. 63.1281(d)(1)(ii), an excursion
occurs when average condenser efficiency
[[Page 52839]]
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). For sources meeting Sec. 63.1281(f)(1), an excursion
occurs when the 30-day average condenser efficiency calculated
according to the requirements of Sec. 63.1282(f)(2)(iii) is less than
the identified 30-day required percent reduction.
* * * * *
(v) For control device whose model is tested under Sec. 63.1282(g)
an excursion occurs when:
(A) The inlet gas flow rate exceeds the maximum established during
the test conducted under Sec. 63.1282(g).
(B) Failure of the monthly visible emissions test conducted under
Sec. 63.1282(h)(3) occurs.
(8) * * *
(i) * * *
(A) During a malfunction when the affected facility is operated
during such period in accordance with Sec. 63.6(e)(1); or
* * * * *
(ii) For each control device, or combinations of control devices,
installed on the same 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.
* * * * *
31. Section 63.1284 is amended by:
a. Revising paragraph (b)(3) introductory text;
b. Removing and reserving paragraph (b)(3)(ii);
c. Revising paragraph (b)(4)(ii);
d. Adding paragraph (b)(7)(ix); and
e. Adding paragraph (f), (g) and (h) to read as follows:
Sec. 63.1284 Recordkeeping requirements.
* * * * *
(b) * * *
(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)(3)(i) through
(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 or
failed to collect required data.
* * * * *
(ii) [Reserved]
* * * * *
(4) * * *
(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, except as
specified in paragraphs (b)(4)(ii)(A) through (C) of this section.
(A) For flares, the records required in paragraph (e) of this
section.
(B) For condensers installed to comply with Sec. 63.1275, records
of the annual 30-day rolling average condenser efficiency determined
under Sec. 63.1282(f) shall be kept in addition to the daily averages.
(C) For a control device whose model is tested under Sec.
63.1282(g), the records required in paragraph (g) of this section.
* * * * *
(7) * * *
(ix) Records identifying the carbon replacement schedule under
Sec. 63.1281(d)(5) and records of each carbon replacement.
* * * * *
(f) The owner or operator of an affected source subject to this
subpart shall maintain records of the occurrence and duration of each
malfunction of operation (i.e., process equipment) or the air pollution
control equipment and monitoring equipment. The owner or operator shall
maintain records of actions taken during periods of malfunction to
minimize emissions in accordance with Sec. 63.1274(a), including
corrective actions to restore malfunctioning process and air pollution
control and monitoring equipment to its normal or usual manner of
operation.
(g) Record the following when using a control device whose model is
tested under Sec. 63.1282(g) to comply with Sec. 63.1281(d),
(e)(3)(ii) and (f)(1):
(1) All visible emission readings and flowrate measurements made
during the compliance determination required by Sec. 63.1282(h); and
(2) All hourly records and other recorded periods when the pilot
flame is absent.
(h) The date the semi-annual maintenance inspection required under
Sec. 63.1283(b) is performed. Include a list of any modifications or
repairs made to the control device during the inspection and other
maintenance performed such as cleaning of the fuel nozzles.
32. Section 63.1285 is amended by:
a. Revising paragraph (b)(1);
b. Revising paragraph (b)(6);
c. Removing paragraph (b)(7);
d. Revising paragraph (d)(1) introductory text;
e. Revising paragraph (d)(1)(i);
f. Revising paragraph (d)(1)(ii) introductory text;
g. Revising paragraph (d)(2) introductory text;
h. Revising paragraph (d)(4)(ii);
i. Adding paragraph (d)(4)(iv);
j. Revising paragraph (d)(10);
k. Adding paragraphs (d)(11) and (d)(12);
l. Revising paragraph (e)(2) introductory text;
m. Revising paragraph (e)(2)(ii)(B);
n. Adding paragraphs (e)(2)(ii)(D) and (E);
o. Adding paragraphs (e)(2)(x), (xi) and (xii); and
p. Adding paragraph (g) to read as follows:
Sec. 63.1285 Reporting requirements.
* * * * *
(b) * * *
(1) The initial notifications required for existing affected
sources under Sec. 63.9(b)(2) shall be submitted as provided in
paragraphs (b)(1)(i) and (ii) of this section.
(i) Except as otherwise provided in paragraph (b)(1)(ii) of this
section, the initial notification 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.
(ii) An affected source identified under Sec. 63.1270(d)(3) shall
submit an initial notification required for existing affected sources
under Sec. 63.9(b)(2) within 1 year after the affected source becomes
subject to the provisions of this subpart or by one year after
publication of the final rule in the Federal Register, whichever is
later. An affected source identified under Sec. 63.1270(d)(3) that
plans to be an area source by three years after publication of the
final rule in the Federal Register, shall include in this notification
a brief, nonbinding description of a schedule for the action(s) that
are planned to achieve area source status.
* * * * *
(6) If there was a malfunction during the reporting period, the
Periodic Report specified in paragraph (e) of this section shall
include the number, duration, and a brief description for each type of
malfunction which occurred during the reporting period and which caused
or may have caused any applicable emission limitation to be exceeded.
The report must also include a description of
[[Page 52840]]
actions taken by an owner or operator during a malfunction of an
affected source to minimize emissions in accordance with Sec.
63.1274(h), including actions taken to correct a malfunction.
* * * * *
(d) * * *
(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 the information in paragraph (d)(1)(iii) of this section and the
information in either paragraph (d)(1)(i) or (ii) of this section.
(i) The condenser 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 is required 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. If the owner or
operator operates a combustion control device model tested under Sec.
63.1282(g), an electronic copy of the performance test results shall be
submitted via e-mail to [email protected]">Oil_and_Gas_[email protected].
* * * * *
(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. The owner or operator shall also submit the information
in paragraph (d)(2)(iii) of this section.
* * * * *
(4) * * *
(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),
(e)(3)(ii), or (f)(1).
* * * * *
(iv) For each carbon adsorber, the predetermined carbon replacement
schedule as required in Sec. 63.1281(d)(5)(i).
* * * * *
(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 the HAP emission reduction of 95.0
percent, or the BTEX limit in Sec. 63.1275(b)(1)(iii) through process
modifications or a combination of process modifications and one or more
control devices.
(11) If the owner or operator installs a combustion control device
model tested under the procedures in Sec. 63.1282(g), the data listed
under Sec. 63.1282(g)(8).
(12) For each combustion control device model tested under Sec.
63.1282(g), the information listed in paragraphs (d)(12)(i) through
(vi) of this section.
(i) Name, address and telephone number of the control device
manufacturer.
(ii) Control device model number.
(iii) Control device serial number.
(iv) Date of control device certification test.
(v) Manufacturer's HAP destruction efficiency rating.
(vi) Control device operating parameters, maximum allowable inlet
gas flowrate.
* * * * *
(e) * * *
(2) The owner or operator shall include the information specified
in paragraphs (e)(2)(i) through (xii) of this section, as applicable.
* * * * *
(ii) * * *
(B) For each excursion caused when the 30-day average condenser
control efficiency is less than the value, 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.
* * * * *
(D) For each excursion caused when the maximum inlet gas flow rate
identified under Sec. 63.1282(g) is exceeded, the report must include
the values of the inlet gas identified and the date and duration of the
period that the excursion occurred.
(E) For each excursion caused when visible emissions determined
under Sec. 63.1282(h) exceed the maximum allowable duration, the
report must include the date and duration of the period that the
excursion occurred.
* * * * *
(x) The results of any periodic test as required in Sec.
63.1282(d)(3) conducted during the reporting period.
(xi) For each carbon adsorber used to meet the control device
requirements of Sec. 63.1281(d)(1), records of each carbon replacement
that occurred during the reporting period.
(xii) For combustion control device inspections conducted in
accordance with Sec. 63.1283(b) the records specified in Sec.
63.1284(h).
* * * * *
(g) Electronic reporting. (1) As of January 1, 2012, and within 60
days after the date of completing each performance test, as defined in
Sec. 63.2 and as required in this subpart, you must submit performance
test data, except opacity data, electronically to the EPA's Central
Data Exchange (CDX) by using the Electronic Reporting Tool (ERT) (see
http://www.epa.gov/ttn/chief/ert/ert_tool.html/). Only data collected
using test methods compatible with ERT are subject to this requirement
to be submitted electronically into the EPA's WebFIRE database.
(2) All reports required by this subpart not subject to the
requirements in paragraphs (g)(1) of this section must be sent to the
Administrator at the appropriate address listed in Sec. 63.13. If
acceptable to both the Administrator and the owner or operator of a
source, these reports may be submitted on electronic media. The
Administrator retains the right to require submittal of reports subject
to paragraph (g)(1) of this section in paper format.
33. Section 63.1287 is amended by revising paragraph (a) to read as
follows:
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 Sec. Sec. 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.
* * * * *
34. Appendix to Subpart HHH of Part 63--Table is amended by
revising Table 2 to read as follows:
Appendix to Subpart HHH of Part 63--Tables
* * * * *
[[Page 52841]]
Table 2 to Subpart HHH of Part 63--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......................
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....................... See Sec. 63.1274(h) for general duty
requirement.
Sec. 63.6(e)(1)(ii)............... No.......................
Sec. 63.6(e)(1)(iii).............. Yes......................
Sec. 63.6(e)(2)................... Yes......................
Sec. 63.6(e)(3)................... No.......................
Sec. 63.6(f)(1)................... No.......................
Sec. 63.6(f)(2)................... Yes......................
Sec. 63.6(f)(3)................... Yes......................
Sec. 63.6(g)...................... Yes......................
Sec. 63.6(h)...................... No....................... Subpart HHH does not contain opacity or visible
emission standards.
Sec. 63.6(i)(1) through (i)(14)... Yes......................
[[Page 52842]]
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...................... But the performance test results must be
submitted within 180 days after the compliance
date.
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)................... No.......................
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......................
63.8(c)(1)(i)....................... No.......................
Sec. 63.8(c)(1)(ii)............... Yes......................
Sec. 63.8(c)(1)(iii).............. Pending..................
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(d)(3)................... Yes...................... Except for last sentence, which refers to an
SSM plan. SSM plans are not required.
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...................... Existing 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...................... Section 63.1284(b)(1) requires sources to
maintain the most recent 12 months of data on-
site and allows offsite storage for the
remaining 4 years of data.
Sec. 63.10(b)(2).................. Yes......................
Sec. 63.10(b)(2)(i)............... No.......................
Sec. 63.10(b)(2)(ii).............. No....................... See Sec. 63.1284(f) for recordkeeping of
occurrence, duration, and actions taken during
malfunction.
Sec. 63.10(b)(2)(iii)............. Yes......................
Sec. 63.10(b)(2)(iv) through No.......................
(b)(2)(v).
Sec. 63.10(b)(2)(vi) through Yes......................
(b)(2)(xiv).
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.
[[Page 52843]]
Sec. 63.10(c)(10) and (c)(11)..... No....................... See Sec. 63.1284(f)for recordkeeping of
malfunctions
Sec. 63.10(c)(12) through (c)(14). Yes......................
Sec. 63.10(c)(15)................. No.......................
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).................. No....................... See Sec. 63.1285(b)(6) for reporting of
malfunctions.
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. 63.11(c), (d), and (e)....... 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. 2011-19899 Filed 8-22-11; 8:45 am]
BILLING CODE 6560-50-P