[Federal Register Volume 77, Number 159 (Thursday, August 16, 2012)]
[Rules and Regulations]
[Pages 49490-49600]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2012-16806]
[[Page 49489]]
Vol. 77
Thursday,
No. 159
August 16, 2012
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; Final
Rule
Federal Register / Vol. 77 , No. 159 / Thursday, August 16, 2012 /
Rules and Regulations
[[Page 49490]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 60 and 63
[EPA-HQ-OAR-2010-0505; FRL-9665-1]
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: Final rule.
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SUMMARY: This action finalizes the review of new source performance
standards for the listed oil and natural gas source category. In this
action the EPA revised the new source performance standards for
volatile organic compounds from leaking components at onshore natural
gas processing plants and new source performance standards for sulfur
dioxide emissions from natural gas processing plants. The EPA also
established standards for certain oil and gas operations not covered by
the existing standards. In addition to the operations covered by the
existing standards, the newly established standards will regulate
volatile organic compound emissions from gas wells, centrifugal
compressors, reciprocating compressors, pneumatic controllers and
storage vessels. This action also finalizes the residual risk and
technology review for the Oil and Natural Gas Production source
category and the Natural Gas Transmission and Storage source category.
This action includes revisions to the existing leak detection and
repair requirements. In addition, the EPA has established in this
action emission limits reflecting maximum achievable control technology
for certain currently uncontrolled emission sources in these source
categories. This action also includes modification and addition of
testing and monitoring and related notification, recordkeeping and
reporting requirements, as well as other minor technical revisions to
the national emission standards for hazardous air pollutants. This
action finalizes revisions to the regulatory provisions related to
emissions during periods of startup, shutdown and malfunction.
DATES: This final rule is effective on October 15, 2012. The
incorporation by reference of certain publications listed in this rule
is approved by the Director of the Federal Register as of October 15,
2012.
ADDRESSES: The EPA has established a docket for this action under
Docket ID. No. EPA-HQ-OAR-2010-0505. All documents in the docket are
listed on the http://www.regulations.gov Web site. Although listed in
the index, some information is not publicly available, e.g.,
confidential business information 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 form. Publicly available docket materials are
available either electronically through http://www.regulations.gov or
in hard copy at the EPA's Docket Center, Public Reading Room, EPA West
Building, Room Number 3334, 1301 Constitution Avenue NW., Washington,
DC 20004. This Docket Facility is open from 8:30 a.m. to 4:30 p.m.
Eastern Standard Time, 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: For further information about this
final action, contact Mr. Bruce Moore, Sector Policies and Programs
Division (E143-05), Office of Air Quality and Standards, Environmental
Protection Agency, Research Triangle Park, North Carolina 27711,
telephone number: (919) 541-5460; facsimile number: (919) 685-3200;
email address: [email protected]. For additional contact information,
see the following SUPPLEMENTARY INFORMATION section.
SUPPLEMENTARY INFORMATION: For specific information regarding risk
assessment and exposure modeling methodology, contact Mr. Mark Morris,
Health and Environmental Impacts Division (C504-06), Office of Air
Quality Planning and Standards, U.S. Environmental Protection Agency,
Research Triangle Park, NC 27711; telephone number (919) 541-5416; fax
number: (919) 541-0840; and email address: [email protected].
Organization of This Document. The information presented in this
preamble is organized as follows:
I. Preamble Acronyms and Abbreviations
II. General Information
A. Executive Summary
B. Does this action apply to me?
C. What are the emission sources affected by this action?
D. Where can I get a copy of this document?
E. Judicial Review
III. Background Information on the NSPS and NESHAP
A. What are the statutory authorities for the NSPS and NESHAP?
B. What is the litigation history?
C. What is the sector-based approach?
D. What are the health effects of pollutants emitted from the
oil and natural gas sector?
IV. Summary of the Final NSPS Rule
A. What are the final actions relative to the NSPS for the Crude
Oil and Natural Gas Production source category?
B. What are the effective and compliance dates for the final
NSPS?
V. Summary of the Significant Changes to the NSPS Since Proposal
A. Gas Well Affected Facilities
B. Centrifugal and Reciprocating Compressor Affected Facilities
C. Pneumatic Controller Affected Facilities
D. Storage Vessel Affected Facilities
E. Equipment Leaks Affected Facilities and Sweetening Unit
Affected Facilities at Onshore Natural Gas Processing Plants
F. Changes to Notification, Recordkeeping and Reporting
Requirements
VI. Summary of the Final NESHAP Rules
A. What are the final rule actions relative to the Oil and
Natural Gas Production (subpart HH) source category?
B. What are the final rule amendments for the Natural Gas
Transmission and Storage (subpart HHH) source category?
C. What is the effective date of this final rule and compliance
dates for the standards?
VII. Summary of the Significant Changes to the NESHAP Since Proposal
A. What are the significant changes since proposal for the Oil
and Natural Gas Production (subpart HH) source category?
B. What are the significant changes since proposal for the
Natural Gas Transmission and Storage (subpart HHH) source category?
VIII. Compliance Related Issues Common to the NSPS and NESHAP
A. How do the rules address startup, shutdown and malfunction?
B. How do the NSPS and NESHAP provide for compliance assurance?
C. What are the requirements for submission of performance test
data to the EPA?
IX. Summary of Significant NSPS Comments and Responses
A. Major Comments Concerning Applicability
B. Major Comments Concerning Well Completions
C. Major Comments Concerning Pneumatic Controllers
D. Major Comments Concerning Compressors
E. Major Comments Concerning Storage Vessels
F. Major Comments Concerning Notification, Recordkeeping and
Reporting Requirements
X. Summary of Significant NESHAP Comments and Responses
A. Major Comments Concerning Previously Unregulated Sources
B. Major Comments Concerning the Risk Review
C. Major Comments Concerning the Technology Review
[[Page 49491]]
D. Major Comments Concerning Notification, Recordkeeping and
Reporting Requirements
XI. What are the cost, environmental and economic impacts of the
final NESHAP and NSPS amendments?
A. What are the air impacts?
B. What are the energy impacts?
C. What are the cost impacts?
D. What are the economic impacts?
E. What are the benefits of this final rule?
XII. 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 Risks 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
K. Congressional Review Act
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:
API American Petroleum Institute
BACT Best Available Control Technology
BDT Best Demonstrated Technology
bpd Barrels Per Day
BMP Best Management Practice
BSER Best System of Emission Reduction
BTEX Benzene, Ethylbenzene, Toluene and Xylene
CAA Clean Air Act
CBM Coal Bed Methane
CDX Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CFR Code of Federal Regulations
CO Carbon Monoxide
CO2 Carbon Dioxide
CO2e Carbon Dioxide Equivalent
DOE United States Department of Energy
e-GGRT Electronic Greenhouse Gas Reporting Tool
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 NEI code 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
PSIA Pounds per Square Inch Absolute
PTE Potential to Emit
QA Quality Assurance
RACT Reasonably Available Control Technology
RBLC RACT/BACT/LAER Clearinghouse
REC Reduced Emissions Completions
REL California EPA 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 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. Executive Summary
1. Purpose of the Regulatory Action
Responding to the requirements of a consent decree, this action
finalizes several rules that apply to the oil and gas production
industry and significantly reduce emissions of air pollutants. More
particularly, the action finalizes:
New source performance standards (NSPS) for the Crude Oil
and Natural Gas Production and onshore natural gas processing plant
source category. The EPA reviewed two existing NSPS for onshore natural
gas processing plant source category under section 111(b) of the Clean
Air Act (CAA). This action improves the existing NSPS and finalizes
standards for certain crude oil and natural gas sources that are not
covered by existing NSPS for this sector.
National Emissions Standards for Hazardous Air Pollutants
(NESHAP) for the Oil and Natural Gas Production source category and the
Natural Gas Transmission and Storage source category. The EPA conducted
risk and technology reviews (RTR) for these rules under section 112 of
the CAA. In addition, the EPA has established emission limits for
certain currently uncontrolled emission sources in these
[[Page 49492]]
source categories. These limits reflect maximum achievable control
technology (MACT).
2. Summary of the Major Provisions of the Regulatory Actions
New Source Performance Standards (NSPS). The newly established NSPS
for the Crude Oil and Natural Gas Production source category regulate
volatile organic compound (VOC) emissions from gas wells, centrifugal
compressors, reciprocating compressors, pneumatic controllers, storage
vessels and leaking components at onshore natural gas processing
plants, as well as sulfur dioxide (SO2) emissions from
onshore natural gas processing plants. This rule sets cost-effective
performance standards for:
Gas wells. The rule covers any gas well that is ``an onshore well
drilled principally for production of natural gas.'' Oil wells (wells
drilled principally for the production of crude oil) are not subject to
this rule. For fractured and refractured gas wells, the rule generally
requires owners/operators to use reduced emissions completions, also
known as ``RECs'' or ``green completions,'' to reduce VOC emissions
from well completions. To achieve these VOC reductions, owners and/or
operators may use RECs or completion combustion devices, such as
flaring, until January 1, 2015; as of January 1, 2015, owners and/or
operators must use RECs and a completion combustion device. The rule
does not require RECs where their use is not feasible, as specified in
the rule. See sections IX.A and IX.B of this preamble for further
discussion.
Storage vessels. Individual storage vessels in the oil and natural
gas production segment and the natural gas processing, transmission and
storage segments with emissions equal to or greater than 6 tons per
year (tpy) must achieve at least 95.0 percent reduction in VOC
emissions. See section IX.E of this preamble for further discussion.
Certain controllers. The rule sets a natural gas bleed rate limit
of 6 scfh for individual, continuous bleed, natural gas-driven
pneumatic controllers located between the wellhead and the point at
which the gas enters the transmission and storage segment. For
individual, continuous bleed, natural gas-driven pneumatic controllers
located at natural gas processing plants, the rule sets a natural gas
bleed limit of zero scfh. See section IX.C of this preamble for further
discussion.
Certain compressors. The rule requires a 95.0 percent reduction of
VOC emissions from wet seal centrifugal compressors located between the
wellhead and the point at which the gas enters the transmission and
storage segment. The rule also requires measures intended to reduce VOC
emissions from reciprocating compressors located between the wellhead
and the point where natural gas enters the natural gas transmission and
storage segment. Owners and/or operators of these compressors must
replace the rod packing based on specified usage or time. See section
IX.D of this preamble for further discussion.
For onshore natural gas processing plants, this final action
revises the existing NSPS requirements for leak detection and repair
(LDAR) to reflect the procedures and leak thresholds established in the
NSPS for Equipment Leaks of VOCs in the Synthetic Organic Chemicals
Manufacturing Industry. This final action also revises the existing
NSPS requirements for SO2 emission reductions 99.8 percent
to 99.9 percent based on reanalysis of the original data.
National Emissions Standards for Hazardous Air Pollutants (NESHAP).
This action also revises the NESHAP for glycol dehydration unit process
vents and leak detection and repair (LDAR) requirements. In the final
rule for major sources at oil and natural gas production facilities, we
have lowered the leak definition for valves at natural gas processing
plants to 500 parts per million (ppm) and thus require the application
of LDAR procedures at this level. In this final rule, we also have
established MACT standards for ``small'' glycol dehydration units,
which were unregulated under the initial NESHAP. Covered glycol
dehydrators are those with an actual annual average natural gas flow
rate less than 85,000 standard cubic meters per day (scmd) or actual
average benzene emissions less than 1 ton per year (tpy), and they must
meet unit-specific limits for benzene, ethylbenzene, toluene and xylene
(BTEX).
In the final rule for major sources at natural gas transmission and
storage facilities, we have established MACT standards for ``small''
glycol dehydrators also not regulated under the initial NESHAP. Covered
glycol dehydrators are those with an actual annual average natural gas
flow rate less than 283,000 scmd or actual average benzene emissions
less than 0.90 Mg/yr, and they must meet unit-specific BTEX emission
limits. v. See sections VII and X of this preamble for further
discussion of both standards.
3. Costs and Benefits
Table 1 summarizes the costs and benefits of this action. See
section XI of this preamble for further discussion.
Table 1--Summary of the Monetized Benefits, Social Costs and Net Benefits for the Final Oil And Natural Gas NSPS
and NESHAP Amendments in 2015
[Millions of 2008$] \1\
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Final NSPS and NESHAP
Final NSPS Final NESHAP amendments amendments combined
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Total Monetized Benefits \2\......... N/A.................... N/A.................... N/A.
Total Costs \3\...................... -$15 million........... $3.5 million........... -$11 million.
Net Benefits......................... N/A.................... N/A.................... N/A.
Non-monetized Benefits \4\........... 11,000 tons of HAP..... 670 tons of HAP........ 12,000 tons of HAP.
190,000 tons of VOC.... 1,200 tons of VOC...... 190,000 tons of VOC.
1.0 million tons of 420 tons of methane.... 1.0 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.
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\1\ All estimates are for the implementation year (2015).
[[Page 49493]]
\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 particulate matter (PM), as well as climate effects associated
with methane, we have determined that quantification of those benefits and co-benefits cannot be accomplished
for this rule in a defensible way. This is not to imply that there are no benefits or co-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
final NSPS reflects the inclusion of revenues from additional natural gas and hydrocarbon condensate recovery
that are estimated as a result of the NSPS. Possible explanations for why there appear to be negative cost
control technologies are discussed in the engineering costs analysis section in the Regulatory Impact Analysis
(RIA).
\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.
The specific control technologies for the final NSPS are anticipated to have minor secondary disbenefits,
including an increase of 1.1 million tons of carbon dioxide (CO2), 550 tons of nitrogen oxides (NOX), 19 tons
of PM, 3,000 tons of carbon monoxide (CO) and 1,100 tons of total hydrocarbons (THC), as well as emission
reductions associated with the energy system impacts. The specific control technologies for the NESHAP are
anticipated to have minor secondary disbenefits, but the EPA was unable to estimate the secondary disbenefits.
The net CO2-equivalent emission reductions are 18 million metric tons.
B. Does this action apply to me?
The regulated categories and entities potentially affected
by the final standards are shown in Table 2 of this preamble.
Table 2--Industrial Source Categories Affected by This Action
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Examples of regulated
Category NAICS code \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 is meant to
provide a guide for readers regarding entities likely to be affected by
this action. If you have any questions regarding the applicability of
this action to a particular entity, consult either the air permitting
authority for the entity or your EPA regional representative as listed
in 40 CFR 60.4 or 40 CFR 63.13 (General Provisions).
C. What are the emission sources affected by this action?
1. What are the emission sources affected by the NSPS?
The emission sources affected by the NSPS include well completions,
pneumatic controllers, equipment leaks from natural gas processing
plants, sweetening units at natural gas processing plants,
reciprocating compressors, centrifugal compressors and storage vessels
which are constructed, modified or reconstructed after August 23, 2011.
Well completions subject to the NSPS are limited to the flowback period
following hydraulic fracturing operations at a gas well affected
facility. These completions include those conducted at newly drilled
and fractured wells, as well as completions conducted following
refracturing operations that may occur at various times over the life
of the well. Pneumatic controllers affected by the NSPS include
continuous bleed, natural gas-driven pneumatic controllers with a
natural gas bleed rate greater than 6 scfh and which commenced
construction after August 23, 2011, in the oil and natural gas
production segment (except for gas processing plants) and continuous
bleed natural gas-driven pneumatic controllers which commenced
construction after August 23, 2011, at natural gas processing plants.
The NSPS applies to centrifugal compressors with wet seals and
reciprocating compressors located in the natural gas production and
processing segments. The NSPS also applies to equipment leaks from
onshore natural gas processing plants and to storage vessels located in
the oil and natural gas production segment, the natural gas processing
segment and the natural gas transmission and storage segment. The NSPS
also affects sweetening units located onshore that process natural gas
from onshore or offshore wells.
2. What are the emission sources affected by the NESHAP?
The emission sources that are affected by the Oil and Natural Gas
Production NESHAP (40 CFR part 63, subpart HH) or the Natural Gas
Transmission and Storage NESHAP (40 CFR part 63, subpart HHH) include
glycol dehydrators and equipment leaks.
D. Where can I get a copy of this document?
In addition to being available in the docket, an electronic copy of
this action will also be available on the World Wide Web (WWW).
Following signature by the Administrator, a copy of the 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 RTR Web site at
http://www.epa.gov/ttn/vatw/rrisk/oarpg.html. This information includes
the most recent version of the rule, source category descriptions,
detailed emissions and other data were used as inputs to the risk
assessments.
E. Judicial Review
Under CAA section 307(b)(1), judicial review of this final rule is
available only by filing a petition for review in the United States
Court of Appeals for the District of Columbia Circuit by October 15,
2012. Under CAA section 307(d)(7)(B), only an objection to this final
rule that was raised with reasonable specificity during the period for
public comment (including any public hearing) can be raised during
judicial review. This section also provides a mechanism for the EPA to
convene a proceeding for reconsideration ``[i]f the person raising an
objection can demonstrate to the Administrator that it was
impracticable
[[Page 49494]]
to raise such objection within [the period for public comment] or if
the grounds for such objection arose after the period for public
comment (but within the time specified for judicial review) and if such
objection is of central relevance to the outcome of the rule[.]'' Any
person seeking to make such a demonstration to us should submit a
Petition for Reconsideration to the Office of the Administrator,
Environmental Protection Agency, Room 3000, Ariel Rios Building, 1200
Pennsylvania Ave. NW., Washington, DC 20004, with a copy to the person
listed in the preceding FOR FURTHER INFORMATION CONTACT section, and
the Associate General Counsel for the Air and Radiation Law Office,
Office of General Counsel (Mail Code 2344A), Environmental Protection
Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20004. Note, under
CAA section 307(b)(2), the requirements established by this final rule
may not be challenged separately in any civil or criminal proceedings
brought by the EPA to enforce these requirements.
III. Background Information on the NSPS and NESHAP
A. What are the statutory authorities for the NSPS and NESHAP?
1. What is the statutory authority for the NSPS?
Section 111 of the 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. Whereas CAA section 112 standards
are issued for new and existing stationary sources, standards of
performance are issued for new and modified stationary sources. These
standards are referred to as 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.
However, the Administrator need not review any such standard if the
``Administrator determines that such review is not appropriate in light
of readily available information on the efficacy'' of the standard.
When conducting a review of an existing performance standard, the EPA
has authority 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
BSER 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 select any control measures that will meet the
emission limits. Upon promulgation, an NSPS becomes a national standard
to which all new sources must comply.
2. What is the statutory authority for the NESHAP?
Section 112 of the CAA establishes a two-stage regulatory process
to address emissions of 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 NESHAP for those sources. ``Major
sources'' are those that emit or have the potential to emit (PTE) 10
tpy or more of a single HAP or 25 tpy or more of any combination of
HAP. For major sources, the technology-based emission 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 MACT
standards.
MACT standards are set 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
sections 112(d)(2)(A)-(E). A 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 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).
[[Page 49495]]
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. CAA section
112(f)(2) 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 must be set (unless a more
stringent standard is required to prevent an adverse environmental
effect, taking into consideration costs, energy, safety and other
relevant factors).
If the MACT standards for HAP that are ``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 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.''). As mentioned, 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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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 has concluded that the EPA's
interpretation of CAA section 112(f)(2) is a reasonable one. See NRDC
v. EPA, 529 F.3d at 1083 (``[S]ubsection 112(f)(2)(B) expressly
incorporates the EPA's interpretation of the Clean Air Act from the
Benzene standard, complete with a citation to the Federal Register'').
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 in the Residual Risk Report to Congress 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)
[[Page 49496]]
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 are 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). See 54 FR 38046.
B. What is the litigation history?
On January 14, 2009, pursuant to section 304(a)(2) of the CAA,
WildEarth Guardians and the San Juan Citizens Alliance filed a
complaint in the United States District Court for the District of
Columbia and alleged 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 5,
2010, the Court entered a consent decree that, as successively
modified, required the EPA to sign by July 28, 2011,\2\ 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 April 3, 2012. On April 2, 2012, the consent decree was modified to
change the date for final action to no later than April 17, 2012.
---------------------------------------------------------------------------
\2\ On April 27, 2011, pursuant to paragraph 10(a) of the
Consent Decree, the parties filed with the Court a written
stipulation to extend the proposal date from January 31, 2011, to
July 28, 2011, and the final action date from November 30, 2011, to
February 28, 2012. On October 28, 2011, pursuant to paragraph 10(a)
of the Consent Decree, the parties filed with the Court a written
stipulation to extend the final action date from February 28, 2012,
to April 3, 2012.
---------------------------------------------------------------------------
C. What is the sector-based approach?
Sector-based approaches are based on integrated assessments of
industrial operations 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, for example the NSPS and NESHAP, consistent with all
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 pollutants, 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 streamlines the monitoring, recordkeeping and reporting
requirements, thus, reducing administrative and compliance complexities
associated with complying with multiple regulations. In addition, the
sector-based approach in this rule promotes a comprehensive control
strategy that maximizes the co-control of multiple regulated pollutants
while obtaining emission reductions as co-benefits.
D. What are the health effects of pollutants emitted from the oil and
natural gas sector?
The final oil and natural gas sector NSPS and NESHAP amendments are
expected to result in significant reductions in existing emissions and
prevent new emissions from expansions of this industry. These emissions
include HAP, VOC (a precursor to both PM2.5 and ozone
formation) and methane (a GHG and a precursor to global ozone
formation). These emissions are associated with substantial health
effects, welfare effects and climate effects. One HAP of particular
concern from the oil and natural gas sector is benzene, which is a
known human carcinogen. PM2.5 is associated with health
effects, including 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. Ozone is associated with health effects,
including hospital and emergency department visits, school loss days
and premature mortality, as well as injury to vegetation and climate
effects.
IV. Summary of the Final NSPS Rule
A. What are the final actions relative to the NSPS for the Crude Oil
and Natural Gas Production source category?
We are revising the existing NSPS, which regulate VOC emissions
from equipment leaks and SO2 emissions from sweetening units
at onshore gas processing plants. In addition, we are promulgating
standards for several new oil and natural gas affected facilities. The
final standards apply to affected facilities that commence
construction, reconstruction or modification after August 23, 2011, the
date of the proposed rule.
The listed Crude Oil and Natural Gas Production source category
covers, at a minimum, those operations for which we are establishing
standards in this final rule. Table 3 summarizes the 40 CFR part 60,
subpart OOOO standards. Further discussion of these changes may
[[Page 49497]]
be found below in this section and in sections V and IX of this
preamble.
Table 3--Summary of 40 CFR Part 60, Subpart OOOO Emission Standards
----------------------------------------------------------------------------------------------------------------
Affected facility Pollutant Standard Compliance dates
----------------------------------------------------------------------------------------------------------------
Hydraulically fractured wildcat and VOC.................... Route flowback emissions to October 15, 2012.
delineation wells. completion combustion
device.
Hydraulically fractured low VOC.................... Route flowback emissions to October 15, 2012.
pressure wells, non-wildcat and completion combustion
non-delineation wells. device.
All other hydraulically fractured VOC.................... Route flowback emissions to Prior to January 1,
gas wells. completion combustion 2015.
device.
All other hydraulically fractured VOC.................... Use REC and route flowback On or after January
gas wells. emissions to completion 1, 2015.
combustion device.
Centrifugal compressors with wet VOC.................... Reduce emissions by 95 October 15, 2012.
seals. percent.
Reciprocating compressors.......... VOC.................... Change rod packing after October 15, 2012.
26,000 hours or after 36
months.
Continuous bleed natural gas-driven VOC.................... Natural gas bleed rate of October 15, 2012.
pneumatic controllers at natural zero.
gas processing plants.
Continuous bleed natural gas-driven VOC.................... Natural gas bleed rate less October 15, 2013.
pneumatic controllers with a bleed than 6 scfh.
rate greater than 6 scfh between
wellhead and natural gas
processing plant or oil pipeline.
Storage vessels with VOC emissions VOC.................... Reduce emissions by 95 October 15, 2013.
equal to or greater than 6 tpy. percent.
Equipment leaks at onshore natural VOC.................... LDAR program............... October 15, 2012.
gas processing plants.
Sweetening units at onshore natural SO2.................... Reduce SO2 emissions based October 15, 2012.
gas processing plants. on sulfur feed rate and
sulfur content of acid gas.
----------------------------------------------------------------------------------------------------------------
1. Standards for Gas Well Affected Facilities
We are finalizing operational standards for completions of
hydraulically fractured and refractured gas wells. For purposes of this
rule, well completion is defined as the flowback period beginning after
hydraulic fracturing and ending with either well shut in or when the
well continuously flows to the flow line or to a storage vessel for
collection, whichever occurs first. The final rule applies to three
subcategories of fractured and refractured gas wells for which well
completion operations are conducted: (1) Wildcat (exploratory) and
delineation gas wells; (2) non-wildcat and non-delineation gas wells
for which the reservoir pressure is insufficient for a REC, commonly
referred to as a ``green completion,'' to be performed, as determined
by a simple calculation involving reservoir pressure, well depth and
flow line pressure at the sales meter (we refer to these wells as ``low
pressure gas wells'') and (3) other fractured and refractured gas
wells. For subcategory (3) wells, each well completion operation begun
on or after January 1, 2015, must employ REC in combination with use of
a completion combustion device to control gas not suitable for entering
the flow line (we refer to this as REC with combustion). For well
completion operations at subcategory (1) wells (exploratory and
delineation gas wells), subcategory (2) wells (low pressure gas wells)
and for well completion operations begun prior to January 1, 2015, at
subcategory (3) gas wells, the final rule requires the control of
emissions using either REC with combustion or just a completion
combustion device. Owners and operators are encouraged to use REC with
combustion during this period.
Well completions subject to the standards are gas well completions
following hydraulic fracturing and refracturing 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. As we explained
in the proposal preamble, a completion operation associated with
refracturing performed at a well is considered a modification under CAA
section 111(a), because physical change occurs to the well resulting in
emissions increases during the refracturing and completion operation.
In response to comment, we further clarify this point in the final
rule, including providing a specific modification provision for well
completions in lieu of the General Provisions in 40 CFR 60.14. For a
more detailed explanation, please see section IX.A of this preamble.
The modification determination and resulting applicability of NSPS to
the completion operation following refracturing of gas wells is limited
strictly to the gas well affected facility and does not by itself
trigger applicability 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
(that is, such equipment is not part of the affected facility).
The final rule provides that uncontrolled well completions
conducted on gas wells that are subsequently refractured on or after
the effective date of this rule are modifications and are subject to
the NSPS. However, gas wells that undergo completion following
refracturing are not considered modified and, as a result, are not
affected facilities under the NSPS if the completion operation is
conducted with the use, immediately upon flowback, of emission control
techniques otherwise required on or after January 1, 2015, for new
wells and satisfies other requirements, including notification,
recordkeeping and reporting requirements.
In the final rule, we provide for a streamlined notification
process for well completions at gas well affected facilities consisting
of an email pre-notification no later than 2 days in advance of
impending completion operations. The email must include information
that had been part of the 30-day advance notification, as described in
the proposed rule, including contact information for the owner and
operator, well identification, geographic
[[Page 49498]]
coordinates of the well and planned date of the beginning of flowback.
In the final rule, the recordkeeping and reporting requirements for
well completions also provide for a streamlining option that owners and
operators may choose in lieu of the standard annual reporting
requirements. The standard annual report must include copies of all
well completion records for each gas well affected facility for which a
completion operation was performed during the reporting period. The
alternative, streamlined annual report for gas well affected facilities
requires submission of a list, with identifying information of all
affected gas wells completed, electronic or hard copy photographs
documenting REC in progress for each well for which REC was required
and the self-certification required in the standard annual report. The
operator retains a digital image of each REC in progress. The image
must include a digital date stamp and geographic coordinates stamp to
help link the photograph with the specific well completion operation.
2. Standards for Compressor Affected Facilities
The final rule requires measures to reduce VOC emissions from
centrifugal and reciprocating compressors. Compressors located at the
wellhead or in the transmission, storage and distribution segments are
not covered by this final rule and, therefore, are not affected
facilities. The final rule contains standards for wet seal centrifugal
compressors located in the natural gas production segment and the
natural gas processing segment up the point at which the gas enters the
transmission and storage segment. The final standards require 95.0
percent reduction of the emissions from each wet seal centrifugal
compressor affected facility. The standard can be achieved by capturing
and routing the emissions to a control device that achieves an emission
reduction of 95.0 percent.
The operational standards for reciprocating compressors in the
final rule require replacement of the rod packing based on usage. The
owner or operator of a reciprocating compressor affected facility is
required to change the rod packing immediately when hours of operation
reach 26,000 hours (equivalent to 36 months of continuous usage).
Alternatively, owners or operators can elect to change the rod packing
every 36 months in lieu of monitoring compressor operating hours. An
owner or operator who elects to meet the 26,000 hour requirement is
required to monitor the duration (in hours) that the compressor is
operated, beginning on the date of initial startup of the reciprocating
compressor affected facility, or on the date of the previous rod
packing replacement, whichever is later.
3. Standards for Pneumatic Controller Affected Facilities
We are also finalizing pneumatic controller VOC standards. The
affected facility is a continuous bleed, natural gas-driven pneumatic
controller with a natural gas bleed rate greater than 6 scfh for which
construction commenced after August 23, 2011, located (1) in the oil
production segment between the wellhead and the point of custody
transfer to an oil pipeline; or (2) in the natural gas production
segment, excluding natural gas processing plants, between the wellhead
and the point at which the gas enters the transmission and storage
segment. Except for controllers located at natural gas processing
plants, each continuous bleed, natural gas-driven pneumatic controller
that emits more than 6 scfh is an affected facility if it is
constructed or modified after August 23, 2011. Pneumatic controllers
with a bleed rate of 6 scfh or less in the oil and natural gas
production segment and all pneumatic controllers located in the natural
gas transmission, storage and distribution segments are not covered by
this final rule and, therefore, are not affected facilities. At natural
gas processing plants, the affected facility is each individual
continuous bleed natural gas-operated pneumatic controller, and the
final rule includes a natural gas bleed rate limit of zero scfh. The
final emission standards for pneumatic controllers at natural gas
processing plants reflect the emission level achievable from the use of
non-natural gas-driven pneumatic controllers. At other locations in the
oil and natural gas production segment, the final rule includes a
natural gas bleed rate limit of 6 standard cubic feet of gas per hour
for an individual pneumatic controller. The standards provide
exemptions in cases where it has been demonstrated that the use of a
natural gas-driven pneumatic controller with a bleed rate above the
applicable standard is required. However, as discussed in section IX.C,
the EPA is allowing a 1-year phase-in period for pneumatic controllers
in the final rule.
4. Standards for Storage Vessels
The final rule contains VOC standards for new, modified or
reconstructed storage vessels located in the oil and natural gas
production, natural gas processing and natural gas transmission and
storage segments. The final rule, which applies to individual storage
vessels, requires that storage vessels with VOC emissions equal to or
greater than 6 tpy achieve at least 95.0 percent reduction in VOC
emissions. For storage vessels constructed, modified or reconstructed
at well sites with no wells already in production at the time of
construction, modification or reconstruction, the final rule provides a
30-day period from startup for the owner or operator to determine
whether the magnitude of VOC emissions from the storage vessel will be
at least 6 tpy. If the storage vessel requires control, the final rule
provides an additional 30 days for the control device to be installed
and operational. For storage vessels constructed, modified or
reconstructed at well sites with one or more wells already in
production at the time of construction, modification or reconstruction,
these estimation and installation periods are not provided because an
estimate of VOC emissions can be made using information on the liquid
production characteristics of the existing wells.
In addition, the final rule provides for a 1-year phase-in period
for storage vessel controls. Refer to section IX.E.4 of this preamble
for further discussion.
5. Standards for Affected Facilities Located at Onshore Natural Gas
Processing Plants
For onshore natural gas processing plants, we are revising the
existing NSPS requirements for LDAR to reflect the procedures and leak
thresholds established by 40 CFR part 60, subpart VVa. Subpart VVa
lowers the leak definition for valves from 10,000 ppm to 500 ppm, and
requires the monitoring of connectors. Pumps, pressure relief devices
and open-ended valves or lines are also monitored.
6. Standards for Sweetening Unit Affected Facilities at Onshore Natural
Gas Processing Plants
The final rule regulates SO2 emissions from natural gas
processing plants by requiring affected facilities to reduce
SO2 emissions by recovering sulfur. The final rule
incorporates the provisions of 40 CFR part 60, subpart LLL into 40 CFR
part 60, subpart OOOO, and minor revisions were made to adapt the
subpart LLL language to subpart OOOO. The final rule also increased the
SO2 emission reduction standard from the subpart LLL
requirement of 99.8 percent to 99.9 percent for units with sulfur
production rate of at least 5 long tons per day. This change is based
on reanalysis of the original data used in the subpart LLL BSER
analysis.
[[Page 49499]]
B. What are the effective and compliance dates for the final NSPS?
The revisions to the existing NSPS standards and the new NSPS
standards promulgated in this action are effective on October 15, 2012.
Affected facilities must be in compliance with the final standards on
the effective date, October 15, 2012.
V. Summary of the Significant Changes to the NSPS Since Proposal
The previous section summarized the requirements that the EPA is
finalizing in this rule. This section will discuss in greater detail
the key changes the EPA has made since proposal. These changes result
from the EPA's review of the additional data and information provided
to us and our consideration of the many substantive and thoughtful
comments submitted on the proposal.
We believe the changes make the final rule more flexible and cost-
effective, address concerns with equipment availability, streamline
recordkeeping and reporting requirements and improve clarity, while
fully preserving or improving the public health and environmental
protection required by the CAA.
A. Gas Well Affected Facilities
We have revised the requirements for gas well affected facilities
since proposal in response to comment. The final rule applies to three
subcategories of fractured and refractured gas wells for which well
completion operations are conducted: (1) Wildcat (exploratory) and
delineation gas wells; (2) non-wildcat and non-delineation gas wells
for which the reservoir pressure is insufficient for a REC to be
performed, as determined by a simple calculation involving reservoir
pressure, well depth and flow line pressure at the sales meter (we
refer to these wells as ``low pressure gas wells''); and (3) other
fractured and refractured gas wells. In the proposed 40 CFR part 60,
subpart OOOO, upon promulgation of this rule, each well completion or
recompletion at a non-exploratory or non-delineation well would have
had to employ REC with combustion. Because of uncertainties in the
supply of equipment and labor over the near-term, we are now requiring
this work practice standard for completion operations begun at
subcategory (3) gas wells (non-exploratory and non-delineation wells)
on or after January 1, 2015. Until this date, flowback emissions must
either be controlled using REC or routed to a completion combustion
device unless it is technically infeasible or unsafe to do so. Owners
and operators are encouraged to use REC when available during this
period. Completion operations at subcategory (1) gas wells (wildcat and
delineation wells) and subcategory (2) gas wells (non-wildcat and non-
delineation low pressure gas wells) begun on or after October 15, 2012
are required to control flowback emissions by using REC with combustion
or by routing emissions to a completion combustion device alone unless
it is technically infeasible or unsafe to do so.
The final rule includes a specific modification provision for well
completions in lieu of the General Provisions in 40 CFR 60.14. For a
more detailed explanation, please see section IX.A of this preamble. In
addition, we have revised the definition of ``flowback period'' to more
clearly define when the flowback period begins and ends.
In the proposed rule, all completions at existing wells (i.e.,
those originally constructed on or before August 23, 2011) that are
subsequently fractured or refractured were considered to be
modifications. In the final rule, completions of wells that are
refractured on or after the rule's effective date are not considered
modified and, as a result, are not affected facilities under the NSPS,
if the completion operation is conducted with the use, immediately upon
flowback, of emission control techniques required on or after January
1, 2015, for new wells and satisfies other requirements, including
notification, recordkeeping and reporting requirements.
In the proposed rule, we prescribed specific equipment to
accomplish an REC. In the final rule, we have removed the required
equipment specifications for REC and added operational standards that
will result in minimizing emissions and maximizing product recovery. In
light of the comments received, we conclude that it is inappropriate
and unnecessary to prohibit the use of other equipment that can be used
to accomplish an REC and that the operational standards can be achieved
using a variety of equipment that can change from well to well.
Initial compliance requirements for gas well affected facilities
have also been revised and streamlined. Owners and operators are now
required to notify the Administrator of the actual date of each well
completion operation by email no later than 2 days prior to the well
completion operation, rather than the proposed requirement of notifying
the Administrator of the date of the well completion operation within
30 days of the commencement of each well completion operation. The
email must include information that had been part of the 30-day advance
notification, as described in the proposed rule, including contact
information for the owner and operator, well identification, geographic
coordinates of the well and planned date of the beginning of flowback.
However, if the owner or operator is subject to state regulations that
require advance notification of well completions and has met those
advance notification requirements, then the owner or operator is
considered to have met the advance notification requirements for gas
well completions under the NSPS.
In the final rule, the recordkeeping and reporting requirements for
well completions also provide for a streamlining option that owners and
operators may choose in lieu of the standard annual reporting
requirements. The standard annual report must include copies of all
well completion records for each gas well affected facility for which a
completion operation was performed during the reporting period. The
alternative, streamlined annual report for gas well affected facilities
requires submission of a list, with identifying information of all
affected gas wells completed, electronic or hard copy photographs
documenting REC in progress for each well for which REC was required
and the self-certification required in the standard annual report. The
operator retains a digital image of each REC in progress. The image
must include a digital date stamp and geographic coordinates stamp to
help link the photograph with the specific well completion operation.
Refer to section IX.B of this preamble and the Responses to
Comments document, available in the docket, for detailed discussion
regarding these changes.
B. Centrifugal and Reciprocating Compressor Affected Facilities
In the final rule, we have made changes that impact both
reciprocating and centrifugal compressor affected facilities in
response to comments requesting clarification. Because we are not
finalizing standards covering them, centrifugal and reciprocating
compressors located in the transmission, storage and distribution
segments are not affected facilities.
In the proposed rule, all centrifugal compressors would be required
to use dry seals. We had also solicited comment on the use of wet seals
with controls as an acceptable alternative to dry seals due to
potential technical infeasibility of using dry seals for certain
applications. Based on comments received, the final rule requires that
centrifugal compressors with wet seals reduce emissions by 95.0
[[Page 49500]]
percent. The standard can be achieved by capturing and routing
emissions from the wet seal fluid degassing system to a control device
that reduces VOC emissions by 95.0 percent. Testing, monitoring,
recordkeeping, reporting and notification requirements associated with
the control devices have also been added. In contrast to the proposed
rule, in the final rule, centrifugal compressors with dry seals are not
affected facilities. More detailed discussion of this change is
presented in section IX.D of this preamble.
As proposed, owners or operators of reciprocating compressor
affected facilities were required to change rod packing after 26,000
hours of operation. This is equivalent to approximately 36 months of
continuous operation. Based on comments we received, we are changing
the final rule to provide operators the option of changing the rod
packing every 36 months instead of tracking compressor hours of
operation and changing rod packing after 26,000 hours of operation.
Refer to section IX.D of this preamble and the Responses to
Comments document, available in the docket, for detailed discussion
regarding these changes.
C. Pneumatic Controller Affected Facilities
For pneumatic controller affected facilities located in the oil and
natural gas production segments, we have revised the definition of
pneumatic controller affected facility from a single pneumatic
controller to a single, continuous bleed, natural gas-driven pneumatic
controller with a continuous bleed rate greater than 6 scfh for which
construction, modification or reconstruction commenced after August 23,
2011. At natural gas processing plants, individual continuous bleed
natural gas-operated pneumatic controllers for which construction,
modification or reconstruction commenced after August 23, 2011, are
affected facilities under this rule. As explained further in section
IX.C of this preamble, this change provides clarity by more
specifically defining the pneumatic controllers we intended to regulate
in this final rule. In addition, only pneumatic controllers located
prior to the point at which the gas enters the transmission and storage
segment are subject to the NSPS. Because we are not finalizing
standards covering them, controllers located in the transmission and
storage segment are not affected facilities. The emission rates we
proposed for pneumatic controllers have not changed in the final rule.
All new pneumatic controller affected facilities are required, in
the final rule, to be tagged with the month and year of installation
and identification that allows traceability to the records for that
controller.
In the proposed rule, each pneumatic controller affected facility
would have to comply upon promulgation. The final rule allows a 1-year
phase-in beginning October 15, 2012 before the bleed rate limit is
effective for an affected facility. We believe this is necessary for at
least two reasons. First, owners and operators would demonstrate
compliance based on information in the manufacturers' specification. We
have concluded that such information is not always included in current
manufacturers' specifications and a period of time is required for
manufacturers to test their products and modify specifications to
include the information. Second, we are not aware of any add-on control
device that is or can be used to reduce VOC emissions from gas-driven
pneumatic devices.
Finally, language in the proposed rule could have been interpreted
to mean that all pneumatic controllers installed in any year after the
proposal date must be reported each year, rather than those installed
only during the reporting period. In order to clarify and streamline
the recordkeeping and reporting requirements associated with pneumatic
controllers, we are requiring only information concerning those
affected facilities constructed, modified or reconstructed during the
reporting period to be included in the annual report.
Refer to section IX.C of this preamble and the Responses to
Comments document, available in the docket, for detailed discussion
regarding these changes.
D. Storage Vessel Affected Facilities
We have modified the definition of ``storage vessel'' to exclude
surge control vessels, knockout vessels and pressure vessels designed
to operate without emissions to the atmosphere. In addition, we have
clarified that we consider a storage vessel that is skid-mounted or
permanently attached to something that is mobile (such as trucks,
railcars, barges or ships) to be subject to 40 CFR part 60, subpart
OOOO if it is intended to be located at a site for at least 180
consecutive days.
In the proposed rule, we established a throughput threshold for
storage vessels below which they were not subject to the NSPS. In order
to remove confusion with respect to the emission factors used to
develop the throughput threshold and to address comments indicating
significant difficulty measuring throughput, we have revised the final
rule such that storage vessels that emit 6 tpy of VOC or more are
subject to the NSPS, based on our analysis in the proposed rule showing
that the proposed NSPS is cost-effective for storage vessels with that
level of VOC emissions. In the final rule, for storage vessels
constructed, modified or reconstructed at well sites with no wells
already in production at the time of construction, the final rule
provides a 30-day period for the owner or operator to determine whether
the magnitude of VOC emissions from the storage vessel will be at least
6 tpy. If the storage vessel requires control, the final rule provides
an additional 30 days for the control device to be installed and
operational. For storage vessels constructed, modified or reconstructed
at well sites with one or more wells already in production at the time
of construction, modification or reconstruction, VOC emissions can be
determined prior to startup. Accordingly, these estimation and
installation periods are not necessary and, therefore, not provided.
Several requirements for storage vessels in the proposed rule
pointed to 40 CFR part 63, subpart HH (the Oil and Natural Gas
Production NESHAP). However, subpart HH regulates HAP while this NSPS
regulates VOC. Therefore, in order to eliminate confusion caused by
cross-referencing another regulation and to tailor the requirements for
VOC regulation, we have incorporated the storage vessel requirements
from subpart HH into 40 CFR part 60, subpart OOOO and modified those
requirements, as appropriate for this rule.
In the proposed rule, each storage vessel required to reduce
emissions would have to comply upon promulgation. In the final rule,
owners or operators are allowed a 1-year phase-in beginning October 15,
2012 before the 95.0-percent control requirement is effective. We
believe this is necessary because of initial problems securing control
devices that are manufacturer-tested and have appropriate documentation
for determining control efficiency. In addition, we believe that owners
or operators will require a period of time to establish the need for
controls and install them where called for. The 1-year phase-in will
also allow owners or operators the necessary time to establish the need
for a control device and procure and install the equipment.
Refer to section IX.E of this preamble and the Responses to
Comments document, available in the docket, for detailed discussion
regarding these changes.
[[Page 49501]]
E. Equipment Leaks Affected Facilities and Sweetening Unit Affected
Facilities at Onshore Natural Gas Processing Plants
We have revised the identification of affected facilities for
equipment leaks at natural gas processing plants. We proposed that
compressors and equipment (as defined in the rule) located at onshore
natural gas processing plants were affected facilities. As discussed
above, compressors (reciprocating and centrifugal) have requirements
under 40 CFR part 60, subpart OOOO that extend beyond the natural gas
processing plant. To remove the duplicative requirements for
compressors at natural gas processing plants, we have revised the
identification of affected facility to exclude compressors from the
standards that apply to equipment leaks at onshore natural gas
processing plants. Refer to the Responses to Comments document,
available in the docket, for detailed discussion regarding these
affected facilities.
F. Changes to Notification, Recordkeeping and Reporting Requirements
In response to comment expressing concern with the burdens
associated with demonstrating and monitoring compliance, we have
reanalyzed the notification, recordkeeping and reporting requirements
in the proposed rule and eliminated duplicative and unnecessary
requirements for all emission points. For well completions,
compressors, pneumatic controllers and storage vessels, we have removed
the General Provisions notification requirements in 40 CFR 60.7(a)(1),
(3) and (4). These requirements relate to notification of construction
and initial performance testing and are more suited to construction of
more traditional facilities (e.g., gas processing plants, refineries
and chemical plants) than the numerous individual pieces of apparatus
(e.g., individual pneumatic controllers, compressor and storage
vessels) that are ``affected facilities'' under this final rule.
Specific notification and initial compliance demonstration requirements
in the final rule make the General Provisions notification requirements
unnecessary for gas well affected facilities.
As mentioned previously, we have also streamlined the notification,
recordkeeping and reporting requirements for gas well affected
facilities. In place of a written notification of each well completion
operation 30 days prior to the completion, owners or operators must
submit a notification no later than 2 days prior to the date of the
completion. This notification may be submitted by email. To avoid
duplicative and potentially conflicting advance notification
requirements, the final rule provides that owners or operators who are
subject to state regulations that require advance notification of well
completions and have met those notification requirements are considered
to have met the advance notification requirements of the NSPS.
Additionally, in lieu of the standard annual reporting requirements,
the final rule allows submission of an annual report for gas well
affected facilities that consists only of a list, with identifying
information of all affected gas wells completed, electronic or hard
copy photographs documenting REC in progress for each well for which
REC was required and the self-certification required in the standard
annual report.
In the affirmative defense provisions of the rule, a citation was
corrected, minor wording changes were made and reporting requirements
were refined. The provisions we retained in the final rule are those we
believe are necessary to assure regulatory agencies and the public that
the owner or operator is in compliance with the final rule. Refer to
section IX.F of this preamble and the Responses to Comments document,
available in the docket, for detailed discussion regarding these
changes.
VI. Summary of the Final NESHAP Rules
A. What are the final rule actions relative to the Oil and Natural Gas
Production (subpart HH) source category?
Table 4 summarizes the changes to 40 CFR part 63, subpart HH.
Further discussion of these changes may be found below in this section
and in sections VII and X of this preamble.
Table 4--Summary of Changes to 40 CFR Part 63, Subpart HH
------------------------------------------------------------------------
Affected source Nature of change Standard
------------------------------------------------------------------------
Small glycol dehydrators.... Established MACT BTEX emission limit:
standards for New sources--4.66 x
previously 10-6 g/scm-ppmv.
unregulated source. Existing sources--
3.28 x 10-4 g/scm-
ppmv.
``Associated equipment''.... Revised definition N/A.
to exclude all
storage vessels.
Valves--equipment leaks..... Revised definition LDAR for valves must
of leak. be applied at 500
ppm.
All affected sources........ Eliminated exemption Standards apply at
from compliance all times.
during periods of
startup, shutdown
and malfunction.
------------------------------------------------------------------------
Pursuant to CAA sections 112(d)(2) and (3), we have established
MACT standards for small glycol dehydrators that were not regulated in
the initial NESHAP. In addition, we have revised the definition of
``associated equipment'' to exclude from the definition of that term
all storage vessels, not just those with potential for flash emissions
(PFE).
With regard to our CAA section 112(d)(6) review, we conclude that
there have been no developments in practices, processes or control
technologies for large glycol dehydrators and storage vessels with PFE.
As noted at proposal, however, there have been relevant developments
for equipment leaks, and we are finalizing the proposed revisions to
the leak definition for valves at natural gas processing plants.
Specifically, under CAA section 112(d)(6), we revised the leak
definition for valves to 500 ppm, thus requiring the application of the
leak detection and repair requirement at this lower detection level. We
did not make other revisions to the standards pursuant to our CAA
section 112(d)(6) review. Our review under CAA section 112(f)(2) also
did not result in revision to the standards. We found that the MACT
standards in 40 CFR part 63, subpart HH (coupled with the new MACT
standard for small glycol dehydrators) provide an ample margin of
safety to protect public health and prevent adverse environmental
effects. Accordingly, we are re-adopting those standards to satisfy the
requirements of CAA section 112(f).
Additionally, we amended 40 CFR part 63, subpart HH to apply the
standards at all times and made other revisions relative to periods of
startup,
[[Page 49502]]
shutdown and malfunction. Lastly, the final rule revises and adds
certain testing and monitoring and related notification, recordkeeping
and reporting requirements and makes certain other minor technical
revisions to the NESHAP.
1. Standards for Small Glycol Dehydration Units
In this final rule, we have established MACT standards under CAA
sections 112(d)(2) and (3) for small glycol dehydration units, which
were left unregulated in the initial NESHAP. This 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). The final MACT standards for small dehydrators at oil and gas
production facilities require that existing affected sources at a major
source meet a unit-specific BTEX limit of 3.28 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.
2. Standards for Equipment Leaks
In the final rule, as a result of our technology review under CAA
section 112(d)(6), we are revising the leak definition for valves to
500 ppm, thus requiring the application of the LDAR requirement at this
lower detection level. This leak definition applies only to valves at
natural gas processing plants, and not other components.
3. Notification, Recordkeeping and Reporting Requirements
The final rule revises certain recordkeeping requirements of 40 CFR
part 63, subpart HH. Specifically, facilities using carbon adsorbers as
a control device are required to 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 of operation (i.e., process
equipment) or the air pollution control equipment and monitoring
equipment.
In conjunction with the new MACT standards for small existing
glycol dehydration units, owners and operators of such affected units
are required to submit an initial notification within 1 year after they
become subject to the provisions of this subpart or by October 15,
2013, whichever is later.
The final amendments to the NESHAP also include additional
requirements for the contents of the periodic reports. The periodic
reports are required to include periodic test results and information
regarding any carbon replacement events that occurred during the
reporting period. Additionally, periodic reports are required to
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 periodic report is also required to include a description of
actions taken by an owner or operator during a malfunction of an
affected source to minimize emissions, including actions taken to
correct a malfunction.
B. What are the final rule amendments for the Natural Gas Transmission
and Storage (subpart HHH) source category?
Table 5 summarizes the changes to 40 CFR part 63, subpart HHH.
Further discussion of these changes may be found below in this section
and in sections VII and X of this preamble.
Table 5--Summary of Changes to 40 CFR Part 63, Subpart HHH
------------------------------------------------------------------------
Affected source Nature of change Standard
------------------------------------------------------------------------
Small glycol dehydrators.... Established MACT BTEX emission limit:
standards for New sources--5.44 x
previously 10-5 g/scm-ppmv.
unregulated source. Existing sources--
3.01 x 10-4 g/scm-
ppmv.
All affected sources........ Eliminated exemption Standards apply at
from compliance all times.
during periods of
startup, shutdown
and malfunction.
------------------------------------------------------------------------
Pursuant to CAA section 112(d)(2) and (3), we have established
MACT standards for small glycol dehydrators that were not regulated in
the initial NESHAP. We have also amended 40 CFR part 63, subpart HHH to
apply the standards at all times, and made other revisions relative to
periods of startup, shutdown and malfunction. Lastly, the final rule
revises and adds certain testing and monitoring and related
notification, recordkeeping and reporting requirements, as well as
makes other minor technical revisions to the NESHAP.
With regard to our CAA section 112(d)(6) review, we conclude that
there have been no developments in practices processes or control
technologies for large glycol dehydrators. We also found that the MACT
standards in 40 CFR part 63, subpart HHH (coupled with the new MACT
standard for small glycol dehydrators) provide an ample margin of
safety to protect public health and prevent adverse environmental
effects. Accordingly, we are re-adopting those standards to satisfy the
requirements of CAA section 112(f). Thus, our reviews under CAA
sections 112(d)(6) and 112(f)(2) did not result in any revisions to the
standards.
1. Standards for Glycol Dehydration Units
In this final rule, we have established MACT standards for small
glycol dehydration units in the Natural Gas Transmission and Storage
source category. This 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 final MACT
standard for this subcategory of small dehydrators requires existing
affected sources to meet a unit-specific BTEX emission limit of 3.01 x
10-4 grams BTEX/scm-ppmv and new affected sources are
required to meet a BTEX limit of 5.44 x 10-5 grams BTEX/scm-
ppmv.
2. Notification, Recordkeeping and Reporting Requirements
The final rule revises certain recordkeeping requirements of 40 CFR
part 63, subpart HHH. Specifically, facilities using carbon adsorbers
as a control device are required to 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 of operation (i.e., process
equipment) or the air pollution control equipment and monitoring
equipment.
In conjunction with the promulgation of the MACT standards for
small glycol dehydration units, the final rule requires that owners and
operators of such affected units submit an initial notification within
1 year after the unit becomes subject to the provisions of this
[[Page 49503]]
subpart or by October 15, 2013, whichever is later.
The final amendments to the NESHAP also include additional
requirements for the contents of the periodic reports. For 40 CFR part
63, subpart HHH, the periodic reports are required to include periodic
test results and information regarding any carbon replacement events
that occurred during the reporting period. Additionally, periodic
reports are required to 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 periodic report is also
required to include a description of actions taken by an owner or
operator during a malfunction of an affected source to minimize
emissions, including actions taken to correct a malfunction.
C. What is the effective date of this final rule and compliance dates
for the standards?
The effective date of this rule is October 15, 2012.
The compliance date for new affected sources (those that commenced
construction or reconstruction on or after August 23, 2011) is
immediately upon initial startup or the effective date of the
standards, October 15, 2012, whichever is later.
The compliance date for existing small glycol dehydration units
that are subject to MACT for the first time (i.e., those that commenced
construction before August 23, 2011) is October 15, 2015.
An affected source at a production field facility that constructed
before August 23, 2011, that was previously determined to be an area
source but becomes a major source on October 15, 2012 due to the
amendment to the associated equipment definition in 40 CFR part 63,
subpart HH, has until October 15, 2015 to comply with the relevant
emission standards.
The compliance date for valves at existing natural gas processing
plants, constructed before August 23, 2011, due to the amendment to the
leak definition in 40 CFR part 63, subpart HH, is 1 year after the
effective date of the standards October 15, 2013.
VII. Summary of the Significant Changes to the NESHAP Since Proposal
The previous section described the requirements that the EPA is
finalizing in this rule. This section discusses in greater detail the
key changes the EPA is making from the proposal. These changes result
from the EPA's review of the additional data and information provided
to us and our consideration of the substantive comments submitted on
the proposal.
We have retained the same approach and methodology to establishing
the standards as described at proposal. We have, however, made some
changes in response to comments, which are described further below. One
change resulted in revisions to the MACT emission limits for small
glycol dehydration units. In addition, based on the comments received,
we are not finalizing the MACT standard for the subcategory of storage
vessels without the PFE, which was a subcategory that was left
unregulated in the 1999 40 CFR part 63, subpart HH rule. Specifically,
based on our review of the comments, we believe that we need additional
data and information to set an emission standard for storage vessels
without the PFE, and we intend to collect the additional data and
propose MACT emission standards under section 112(d)(2) and (3) of the
CAA for such storage vessels. Finally, we are retaining the 0.9 Mg/yr
compliance option for large dehydration units.
A. What are the significant changes since proposal for the Oil and
Natural Gas Production (subpart HH) source category?
1. Changes Made to Amendments Proposed Under the Authority of CAA
Sections 112(d)(2) and (3)
Under the authority of sections 112(d)(2) and (3) of the CAA, we
proposed amendments to 40 CFR part 63, subpart HH by adding
requirements for previously unregulated units; specifically, we
proposed standards for small glycol dehydration units and storage
vessels without the PFE.
In the final amendments for 40 CFR part 63, subpart HH, we have
revised the proposed MACT standards for small glycol dehydration units
in response to comments that we did not take into account variability
in the development of the MACT floor. In our proposal, the MACT
standards for existing affected sources was a unit-specific BTEX limit
of 1.10 x 10-4 g BTEX/scm-ppmv and for new affected sources
was a BTEX limit of 4.66 x 10-6 g BTEX/scm-ppmv. In this
final rule, we accounted for variability by using an upper prediction
limit to develop a revised BTEX emission limit for existing small
glycol dehydration units of 3.28 x 10-4 grams BTEX/standard
cubic meters (scm)-parts per million by volume (ppmv) and for new small
glycol dehydration units the revised BTEX limit is 4.66 x
10-6 grams BTEX/scm-ppmv. The process for developing these
emissions limitations is documented in the Response to Comments
document and a technical memorandum, both of which are in the docket.
Finally, as noted above, in response to comments, we are not
finalizing MACT standards for storage vessels without the PFE in this
rule. We received numerous comments expressing concerns with how we
established the proposed standards for this subcategory. In response to
such comments, we have re-evaluated the proposed MACT standards and
concluded that we need (and intend to gather) additional data on these
sources in order to analyze and establish MACT emission standards for
this subcategory of storage vessels under section 112(d)(2) and (3) of
the CAA. See the Response to Comments document for additional
discussion.
2. Changes Made to Amendments Proposed Under the Authority of CAA
Section 112(f)(2)
We proposed to eliminate the 0.9 Mg/yr benzene compliance option
for large glycol dehydration units because, in the proposed rule, we
estimated that the emissions allowed as the result of this compliance
option resulted in estimated cancer risks up to 400-in-1-million. We
received multiple comments concerning our proposed risk estimate. After
reviewing these comments, we discovered that we had significantly
overestimated the allowable emissions associated with this compliance
option. First, for several sources, including the source that we
predicted had the 400-in-1 million MIR, we used an incorrect factor (or
multiplier) to scale up actual emissions associated with sources that
could utilize the compliance option level of 0.9 Mg/yr to allowables.
We used an incorrect factor due to an inadvertent transcription error
in our calculations. Second, we learned that the risk assessment
supporting the proposed rule erroneously included several area sources,
which are not subject to 40 CFR part 63, subpart HH and thus should not
have been included in the CAA section 112(f) risk assessment. After
revising the risk assessment to remove area sources, and considering
the MACT standard promulgated today for small glycol dehydrators
pursuant to CAA sections 112(d)(2) and (3), the MIR for the Oil and
Natural Gas Production source category based on actual and allowable
emissions is 10-in-1 million, compared to the 400-in-1 million\3\ based
on
[[Page 49504]]
allowable emissions and 40-in-1 million based on actual emissions that
were estimated in the proposed rule.
---------------------------------------------------------------------------
\3\ At proposal, we used an incorrect factor (or multiplier) in
calculating allowable emissions for the source that, at proposal,
had an estimated MIR of 400-in-1 million. Since proposal, we have
learned that this source is an area source and thus is not subject
to the Subpart HH MACT standards. As such, we removed this source
from our section 112(f) risk analysis. In any event, we have
determined that even if this area source were to have actual
emissions at the 0.9 Mg/yr level, its risk would be 3-in-1 million.
---------------------------------------------------------------------------
As the result of our revised risk analysis, we have determined that
approximately 120,000 people are estimated to have cancer risks at or
above 1-in-1 million, compared to 160,000 people estimated in the
proposed rule. Total estimated cancer incidence from the source
category is 0.02 excess cancer cases per year, or one case in every 50
years. This estimate is unchanged from the proposed rule because the
incidence from a small number of sources typically does not affect
total incidence reported to one significant figure. The estimate from
the proposed rule of maximum chronic non-cancer TOSHI value (0.1) is
unchanged, driven by naphthalene emissions from fugitive sources. The
maximum acute non-cancer hazard quotient value (9, based on the
California EPA reference exposure level (REL) for benzene) is also
unchanged from the proposed rule. Although driven by the same pollutant
that drives the MIR, benzene, the maximum acute hazard quotient value
did not change from the proposed rule because the source driving the
acute value was not identified as an area source and, thus, remained in
the revised analysis. It is common for the maximum acute hazard
quotient and cancer MIR not to coincide because the acute value is
strongly dependent on short-term meteorology and the distance to the
facility property boundary, whereas the MIR is dependent on long-term
meteorology and the distance to census block receptors. There are 13
cases in the source category (out of approximately 1,000 facilities)
where the REL is exceeded by more than a factor of 2.
Based on the conservative nature of the acute exposure scenario
used in the screening assessment for this source category, the EPA has
judged that, considering all associated uncertainties, the potential
for effects from acute exposures is low. Screening estimates of acute
exposures were evaluated for each 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 present at this location at a time when both
the peak emission rate and worst-case dispersion conditions occur.
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. The acute modeling
scenario is worst-case because of the confluence of peak emission rates
and worst-case dispersion conditions. Also, the generally sparse
populations near the facilities with the highest estimated 1-hour
exposures make it less likely that a person would be near the plant to
be exposed.
We also conducted a facility-wide risk assessment. The maximum
facility-wide risk estimate of 100-in-1 million is unchanged from the
proposed rule. Also unchanged from proposal is the fact that the
facility-wide risk is driven by emissions from reciprocating internal
combustion engines (RICE) and these engines are not part of the Oil and
Natural Gas Production source category. In fact, oil and natural gas
production operations contribute only about one percent or less to the
total facility-wide risks. In the last few years, the Agency has
revised the MACT standards for certain RICE. See 75 FR 9648 and 51570.
Although it is difficult to discern from the available data which types
of RICE are driving the facility-wide risk, it is important to note
that the 2005 National Emissions Inventory (NEI) data on which we
modeled risk did not take into account the recent MACT revisions to the
RICE rule. Finally, our assessment that the potential for significant
human health risks due to multipathway exposures or adverse
environmental effects is low has not changed since proposal (see 76 FR
52774).
Consistent with the approach established in the Benzene NESHAP, the
EPA weighed all health risk measures and information, including the
maximum individual cancer risk, the cancer incidence, the number of
people exposed to a risk greater than 1-in-1-million, the distribution
of risks in the exposed population, and the uncertainty of our risk
calculations in determining whether the risk posed by emissions from
Oil and Natural Gas Production is acceptable. In this case, because the
MIR is well below 100-in-1-million, and because a number of other
factors indicate relatively low risk concern, including low cancer
incidence, low potential for adverse environmental effects or human
health multi-pathway, and unlikely chronic and acute noncancer health
impacts, we conclude that the level of risk associated with the Oil and
Natural Gas Production source category MACT standards (including the
small glycol dehydrator MACT standard issued here) is acceptable.\4\
---------------------------------------------------------------------------
\4\ We reach the same conclusion even if we do not consider the
new MACT for small glycol dehydrators in our acceptability
determination. Indeed, focusing solely on the standards in the
existing MACT, the level of risk associated with such standards
would remain 10-in-1 million, and thus our acceptability
determination does not change. There is one facility that is a small
glycol dehydrator that has an MIR of 10-in-1 million. After
imposition of the MACT for small glycol dehydrators, however, this
unit would have an MIR of 7-in-1 million. Also, see memorandum
titled Supplemental Facility Information Obtained from Various
State/Local Agencies and Additional Analysis, March 20, 2012.
---------------------------------------------------------------------------
In making our proposed ample margin of safety determination under
CAA section 112(f)(2), we subsequently evaluated the risk reductions
and costs associated with various emissions control options to
determine whether we should impose additional standards to reduce risks
further. As stated above, we made certain revisions to the risk
assessment in response to comments and the resulting MIR for 40 CFR
part 63, subpart HH is 10-in-1 million. We have not identified any
emission control options that would reduce emissions and risk
associated with subpart HH sources for glycol dehydration units and
storage vessels. Our proposed amendment to remove the 0.9 Mg/yr
compliance option does not affect the risk driver, which is fugitive
emissions. As a result, we are retaining the 0.9 Mg/yr compliance
option in the final rule. We have determined that the risks associated
with the level of emissions allowed by the MACT standards are driven by
fugitive emissions (i.e., leaks).
Since a LDAR program is the typical method for reducing emissions
from fugitive sources, we considered requiring a LDAR program to reduce
risk for this source category. The NEI dataset for this source category
contains approximately 2,500 emission points that we characterized as
fugitive. These emission points are located at 639 facilities. The
fugitive emissions associated with those 639 facilities are 747 tons of
HAP.
In evaluating the effectiveness of a LDAR program at these
facilities we looked at two different LDAR programs--one is a program
equivalent to 40 CFR part 60, subpart VV, and the second is a more
stringent program equivalent to 40 CFR part 60, subpart VVa.\5\ A LDAR
program equivalent to subpart VV can achieve emission reductions of
approximately 39 percent with capital and annual costs of
[[Page 49505]]
$237,700 and $79,419 per facility, respectively. Therefore, such a
program for the 639 facilities would be expected to reduce emissions by
249 tons of HAP with total capital and annual costs of $152 million and
$50.7 million, respectively. The cost effectiveness would be
approximately $204,000 per ton of HAP.
---------------------------------------------------------------------------
\5\ See memorandum titled Equipment Leak Emission Reduction and
Cost Analysis for Well Pads, Gathering and Boosting Stations, and
Transmission and Storage Facilities Using Emission and Cost Data
from the Uniform Standards, April 17, 2012.
---------------------------------------------------------------------------
A LDAR program equivalent to 40 CFR part 60, subpart VVa can
achieve emission reductions of approximately 43 percent overall with
capital and annual costs of $241,000 and $82,900 per facility,
respectively. Therefore, an LDAR program for the 639 facilities would
be expected to reduce emissions by 275 tons of HAP, with total capital
and annual costs of $154 million and $53 million, respectively. The
cost effectiveness would be approximately $193,000 per ton of HAP
reduced. These additional control requirements would reduce the MIR for
the source category from 10-in-1 million to approximately 7-in-1
million.
As explained in the proposal, in accordance with the approach
established in the Benzene NESHAP, we weigh 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 and deciding whether
standards are necessary to reduce risks further. Considering all of
this information, we conclude that the costs of the options analyzed
are not reasonable considering the emissions reductions and risk
reductions potentially achievable with the control measures evaluated.
Thus, we conclude that the MACT standards in 40 CFR part 63, subpart HH
(coupled with the new MACT standard for small glycol dehydrators)
provide an ample margin of safety to protect public health and prevent
adverse environmental effects. Accordingly, we are re-adopting those
standards to satisfy the requirements of CAA section 112(f).
3. Changes Made to Standards Proposed Under the Authority of CAA
Section 112(d)(6)
As discussed in detail in the preamble for the proposed rule (76 FR
52784), we conducted a technology review for glycol dehydration units,
storage vessels and equipment leaks under the authority of CAA section
112(d)(6). We assessed developments in practices, processes and control
technologies sources for those regulated under the initial NESHAP and
determined that it was cost-effective to lower the leak definition for
valves at natural gas processing plants. We did not identify
developments in practices, processes and control technologies for
glycol dehydration units and storage vessels. As a result of this
assessment, we proposed revisions to 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. No significant changes since
proposal were made to the equipment leak standards proposed under the
authority of section 112(d)(6) of the CAA.\6\
---------------------------------------------------------------------------
\6\ Memorandum from Brown, Heather, EC/R Inc., to Moore, Bruce,
U.S. EPA, titled Technology Review for the Final Amendments to
Standards for the Oil and Natural Gas Production and Natural Gas
Transmission and Storage Source Categories.
---------------------------------------------------------------------------
4. Other Changes to the Proposed Rule
We are revising the emission reduction demonstrated using the
manufacturers performance test from 98.0 percent to 95.0 percent.
Specifically, if an owner or operator chooses to install a combustion
control device that is tested under, and passes, the prescribed
manufacturers performance test the final rule states that the control
device has demonstrated a destruction efficiency of 95.0 percent. This
change is a result of comments and data provided on the actual
performance of these devices in the field.
In the proposed rule, we proposed that the standards apply at all
times and removed provisions that provided an exemption from the
emission standards during SSM. In response to comments that the
monitoring and reporting provisions related to excursions occurring
during SSM events that remain in the subpart suggest exemption and
therefore should be removed, we are removing these provisions in the
final rule.
Refer to the Reponses to Comments document, available in the
docket, for detailed discussion regarding these changes.
B. What are the significant changes since proposal for the Natural Gas
Transmission and Storage (subpart HHH) source category?
1. Changes Made to Amendments Proposed Under the Authority of CAA
Sections 112(d)(2) and (3)
Under the authority of sections 112(d)(2) and (3) of the CAA, we
proposed amendments to 40 CFR part 63, subpart HHH by adding
requirements for previously unregulated units; specifically, we
proposed standards for small glycol dehydration units.
In the final amendments for 40 CFR part 63, subpart HHH, we have
revised the proposed BTEX limits for small glycol dehydration units in
response to comments that we did not take into account variability in
the development of the MACT floor. We had proposed a unit-specific BTEX
emission limit of 6.42 x 10-5 grams BTEX/scm-ppmv for
existing sources and a BTEX limit of 1.10 x 10-5 g BTEX/scm-
ppmv for new sources. In the final rule, we accounted for variability
by using an upper prediction limit to develop a revised emission limit
for existing affected sources of 3.10 x 10-4 g BTEX/scm-ppmv
and for new affected sources is a BTEX limit of 5.44 x 10-5
grams BTEX/scm-ppmv. The process for developing these emissions
limitations is documented in the response to comments document and a
technical memorandum both of which can be found in the docket.
2. Changes to Amendments Proposed Under the Authority of CAA Section
112(f)(2)
We proposed to eliminate the 0.9 Mg/yr benzene compliance option
for large glycol dehydration unit process vents because, in the
proposed rule, we estimated that the emissions allowed as the result of
this compliance option resulted in estimated cancer risks up to 90-in-
1-million. In response to comments, we learned that the risk assessment
supporting the proposed rule erroneously included some sources that
have permanently shut down, and several area sources, which are not
subject to 40 CFR part 63, subpart HHH and, thus, should not have been
included in the CAA section 112(f) risk assessment. After revising the
risk assessment to remove these sources and considering the MACT
standards promulgated here pursuant to CAA section 112(d)(2) and (3),
the MIR for the Natural Gas Transmission and Storage source category
based on actual and allowable emissions is 20-in-1 million, compared to
the 90-in-1 million based on allowable emissions and 20-in-1 million
based on actual emissions estimated in the proposed rule.
As the result of our revised risk analysis, we have determined that
approximately 1,100 people are estimated to have cancer risks at or
above 1-in-1 million, compared to 2,500 people estimated in the
proposed rule. Total estimated cancer incidence from the source
category is 0.001 excess cancer cases per year, or one case in every
1,000 years. This estimate is unchanged from the proposed rule
[[Page 49506]]
because the incidence from a small number of sources typically does not
affect total incidence reported to one significant figure. The estimate
from the proposed rule of maximum chronic non-cancer TOSHI value (0.2)
is unchanged, driven by benzene emissions from fugitive sources. The
maximum acute non-cancer hazard quotient value (4, based on the benzene
REL) changed from the proposed rule; the value in the proposed rule was
5, but was associated with an area source that was removed from the
risk assessment. There are two cases in the source category (out of
approximately 300 facilities) where the REL is exceeded by more than a
factor of 2.
Based on the conservative nature of the acute exposure scenario
used in the screening assessment for this source category, the EPA has
judged that, considering all associated uncertainties, the potential
for effects from acute exposures is low. Screening estimates of acute
exposures were evaluated for each 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 present at this location at a time when both
the peak emission rate and worst-case dispersion conditions occur.
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. The acute modeling
scenario is worst-case because of the confluence of peak emission rates
and worst-case dispersion conditions. Also, the generally sparse
populations near the facilities with the highest estimated 1-hour
exposures make it less likely that a person would be near the plant to
be exposed.
We also conducted a facility-wide risk assessment. The maximum
facility-wide risk estimate of 200-in-1 million is unchanged from the
proposed rule. Also unchanged from proposal is the fact that the
facility-wide risk is driven by emissions from reciprocating internal
combustion engines (RICE) and these engines are not part of the Natural
Gas Transmission and Storage source category. In fact, natural gas
transmission and storage operations contribute only about one percent
or less to the total facility-wide risks. In the last few years, the
Agency has revised the MACT standards for certain RICE. See 75 FR 9648
and 51570. Although it is difficult to discern from the available data
which types of RICE are driving the facility-wide risk, it is important
to note that the 2005 NEI data on which we modeled risk did not take
into account the recent MACT revisions to the RICE rule. Finally, our
assessment that the potential for significant human health risks due to
multipathway exposures or adverse environmental effects is low has not
changed since proposal (see 76 FR 52774).
Consistent with the approach established in the Benzene NESHAP, the
EPA weighed all health risk measures and information, including the
maximum individual cancer risk, the cancer incidence, the number of
people exposed to a risk greater than 1-in-1-million, the distribution
of risks in the exposed population and the uncertainty of our risk
calculations in determining whether the risk posed by emissions from
natural gas transmission and storage is acceptable. In this case,
because the MIR is well below 100-in-1-million, and because a number of
other factors indicate relatively low risk concern, including low
cancer incidence, low potential for adverse environmental effects or
human health multi-pathway effects, and unlikely chronic and acute
noncancer health impacts, we conclude that the level of risk associated
with the Natural Gas Transmission and Storage source category MACT
standards (including those MACT standards issued here) is
acceptable.\7\
---------------------------------------------------------------------------
\7\ We reach the same conclusion even if we do not consider the
new MACT for small glycol dehydrators in our acceptability
determination. Indeed, focusing solely on the standards in the
existing MACT, the level of risk associated with such standards
would remain 20-in-1 million, and thus our acceptability
determination would not change. The glycol dehydrators analyzed all
had risks well below 20-in-1 million.
---------------------------------------------------------------------------
In making our proposed ample margin of safety determination under
CAA section 112(f)(2), we subsequently evaluated the risk reductions
and costs associated with various emissions control options to
determine whether we should impose additional standards to reduce risks
further. As stated above, we made certain revisions to the risk
assessment in response to comments and the resulting MIR for 40 CFR
part 63, subpart HHH is 20-in-1 million. We have not identified any
emission control options that would reduce emissions and risk
associated with subpart HHH sources for glycol dehydration units. Our
proposed amendment to remove the 0.9 Mg/yr compliance option does not
affect the risk driver, which is fugitive emissions. As a result, we
are retaining the 0.9 Mg/yr compliance option in the final rule.
We have determined that the risks associated with the level of
emissions allowed by the MACT standards are driven by fugitive
emissions (i.e., leaks). Since a LDAR program is the typical method for
reducing emissions from fugitive sources, we evaluated the costs and
emissions reductions associated with requiring such a program to reduce
risk for this source category. The NEI dataset for the natural gas
transmission and storage source category contains approximately 314
emission points that we characterized as being fugitive in nature.
These emission points are located at 212 facilities. The fugitive
emissions associated with those 212 facilities are 187 tons of HAP.
In evaluating the effectiveness of a LDAR program at these
facilities we looked at two different LDAR programs--one is a program
equivalent to 40 CFR part 60, subpart VV, and the second is a more
stringent program equivalent to 40 CFR part 60, subpart VVa.\8\ A LDAR
program equivalent to subpart VV can achieve emission reductions of
approximately 51 percent with capital and annual costs of $361,800 and
$142,600 per facility, respectively. Therefore, such a program for 212
facilities would be expected to reduce emissions by 95.4 tons of HAP
and have total capital and annual costs of $76.7 million and $30.2
million, respectively. The cost effectiveness would be approximately
$317,000 per ton of HAP.
---------------------------------------------------------------------------
\8\ See memorandum titled Equipment Leak Emission Reduction and
Cost Analysis for Well Pads, Gathering and Boosting Stations, and
Transmission and Storage Facilities Using Emission and Cost Data
from the Uniform Standards, dated April 17, 2012.
---------------------------------------------------------------------------
A LDAR program equivalent to 40 CFR part 60, subpart VVa can
achieve emission reductions of approximately 78 percent overall with
capital and annual costs of $369,500 and $154,300 per facility,
respectively. Therefore, a LDAR program for 212 facilities would be
expected to reduce emissions by 146 tons of HAP with total capital and
annual costs of $78.3 million and $32.7 million, respectively. The cost
effectiveness would be approximately $224,000 per ton of HAP. These
additional control requirements would reduce the MIR from the source
category to approximately 3-in-1 million for the subpart VVa level of
control and 7-in-1-million for the 40 CFR part 60, subpart VV level of
control.
As explained in the proposal, in accordance with the approach
established in the Benzene NESHAP, we weigh 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 and
[[Page 49507]]
deciding whether standards are necessary to reduce risks further.
Considering all of this information, we conclude that the costs of the
options analyzed are not reasonable considering the emissions
reductions and risk reductions potentially achievable with the control
measures. Thus, we conclude that the MACT standards in 40 CFR part 63,
subpart HHH (coupled with the new MACT standard for small glycol
dehydrators) provide an ample margin of safety to protect public health
and prevent adverse environmental effects. Accordingly, we are re-
adopting those standards to satisfy the requirements of CAA section
112(f)(2).
3. Changes Made to Amendments Proposed Under the Authority of CAA
Section 112(d)(6)
As discussed in detail in the preamble for the proposed rule (76 FR
52784), we conducted a technology review for glycol dehydration units
under the authority of CAA section 112(d)(6). We did not identify
developments in practices, processes and control technologies for large
glycol dehydration units. As a result of this assessment, we did not
propose amendments to 40 CFR part 63, subpart HHH. We have not made any
changes since proposal under the authority of CAA section 112(d)(6).\9\
Further discussion on our technology review analysis can be found in
section X.C of this preamble, and in the Response to Comments document.
---------------------------------------------------------------------------
\9\ See footnote 6.
---------------------------------------------------------------------------
4. Other Changes to the Proposed Rule
We are revising the emission reduction efficiency demonstration
using the manufacturer's performance test from 98.0 percent to 95.0
percent. Specifically, if an owner or operator chooses to install a
combustion control device that is tested under, and passes, the
prescribed manufacturer's performance test, the final rule states that
the control device has demonstrated a reduction efficiency of 95.0
percent. This change is a result of comments and data provided on the
actual performance of these devices in the field.
In the proposed rule, we proposed that the standards apply at all
times and removed provisions that provided an exemption from the
emission standards during SSM. In response to comments that the
monitoring and reporting provisions related to excursions occurring
during SSM events that remain in the subpart suggest exemption and
therefore should be removed, we are removing these provisions in the
final rule.
VIII. Compliance Related Issues Common to the NSPS and NESHAP
A. How do the rules address startup, shutdown and 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
are 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.
As proposed in the NESHAP, we have eliminated the SSM exemption in
this rule. Consistent with Sierra Club v. EPA, the EPA has established
standards in both rules that apply at all times. We have also revised
Table 3 (the NESHAP General Provisions table) in several respects. For
example, we have eliminated the incorporation of the NESHAP General
Provisions' requirement that the source develop an SSM plan. We have
also eliminated or revised certain NESHAP recordkeeping and reporting
that related to the SSM exemption. The EPA has attempted to ensure that
we have not included in the regulatory language, for the NSPS and
NESHAP, any provisions that are inappropriate, unnecessary or redundant
in the absence of the SSM exemption.
In establishing the standards in both rules, the EPA has taken into
account startup and shutdown periods and, for the reasons explained in
section IX of this preamble for the NSPS and in section X of this
preamble for the NESHAP, did not establish different standards for
those periods. Based on the information available in the record about
actual operations during startups and shutdowns, 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) and as ``any sudden, infrequent,
and not reasonably preventable failure of air pollution control
equipment, process equipment, or a process to operate in a normal or
usual manner * * *'' (40 CFR 60.2). The EPA has determined that CAA
sections 111 and 112 do not require that emissions that occur during
periods of malfunction be factored into development of CAA section 111
or 112 standards.
CAA section 111 standards--See section III of this preamble for a
detailed discussion on how the EPA sets or revises CAA section 111 NSPS
to reflect the degree of emission limitation achievable through the
application of the BSER.
CAA section 112 standards--Under CAA section 112, emissions
standards for new sources must be no less stringent than the level
``achieved'' by the best controlled similar source and for existing
sources, generally must be no less stringent than the average emission
limitation ``achieved'' by the best performing 12 percent of sources in
the category. Nothing in CAA section 112 directs the agency to consider
malfunctions in determining the level ``achieved'' by the best
performing or best controlled sources when setting emission standards.
Moreover, while the EPA accounts for variability in setting emissions
standards consistent with the CAA section 112 case law, nothing in that
case law requires the agency to consider malfunctions as part of that
analysis. CAA section 112 uses the concept of ``best controlled'' and
``best performing'' unit in defining the level of stringency that CAA
section 112 performance standards must meet. Applying the concept of
``best controlled'' or ``best performing'' to a unit that is
malfunctioning presents significant difficulties, as malfunctions are
sudden and unexpected events.
Further, accounting for malfunctions in setting NESHAP or NSPS
standards would be difficult, if not impossible, given the myriad
different types of malfunctions that can occur across all sources in
the category and given the difficulties associated with predicting or
accounting for the frequency, degree and duration of various
malfunctions that might occur. As such, the performance of units that
are malfunctioning is not ``reasonably'' foreseeable. See, e.g., Sierra
Club v.
[[Page 49508]]
EPA, 167 F.3d 658, 662 (D.C. Cir. 1999) (``[T]he EPA typically has wide
latitude in determining the extent of data-gathering necessary to solve
a problem. We generally defer to an agency's decision to proceed on the
basis of imperfect scientific information, rather than to `invest the
resources to conduct the perfect study.' ''); see, also, Weyerhaeuser
Co. 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.''). In addition, in the
NESAHP context, the goal of a best controlled or best performing source
is to operate in such a way as to avoid malfunctions of the source and
accounting for malfunctions could lead to standards that are
significantly less stringent than levels that are achieved by a well-
performing non-malfunctioning source. Similarly, in the NSPS context,
accounting for malfunctions when setting standards of performance under
CAA section 111, 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 could
lead to standards that are significantly less stringent than levels
that are achieved by a well-performing non-malfunctioning source. The
EPA's approach to malfunctions is consistent with CAA section 112 and
CAA section 111 and is a reasonable interpretation of the statute.
Finally, the EPA recognizes that even equipment that is properly
designed and maintained can sometimes fail and that such failure can
sometimes cause a violation 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, adding to the
final NSPS and NESHAP an affirmative defense to civil penalties for
violations of emission standards that are caused by malfunctions. See
40 CFR 63.761 for sources subject to the Oil and Natural Gas Production
MACT standards; 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 have added 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 or Natural Gas
Transmission and Storage 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
NSPS must prove by a preponderance of the evidence that it has met all
of the elements set forth in 40 CFR 60.41Da (NSPS). See 40 CFR 22.24.
The criteria ensure that the affirmative defense is available only
where the event that causes a violation of the emission standard meets
the narrow definition of malfunction in 40 CFR 60.2 (NSPS) and 40 CFR
63.2 (NESHAP), respectively, (sudden, infrequent, not reasonably
preventable and not caused by poor maintenance and/or careless
operation). For example, the final NSPS and NESHAP provide that to
successfully assert the affirmative defense, the source must prove by a
preponderance of the evidence that the violation ``[w]as caused by a
sudden, infrequent, and unavoidable failure of air pollution control
and 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 MACT standards, 40 CFR 63.1272 for sources subject to the
Natural Gas Transmission and Storage MACT standards, and 40 CFR
60.5415(h) for the Standards of Performance for Crude Oil and Natural
Gas Production, Transmission and Distribution, and to prevent future
malfunctions. For example, the final NSPS and NESHAP provide that the
source must prove by a preponderance of the evidence that ``[r]epairs
were made as expeditiously as possible when a violation occurred * *
*'' and that ``[a]ll possible steps were taken to minimize the impact
of the violation 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
part 22.27).
The EPA proposed and is now finalizing an affirmative defense in
the final NSPS and NESHAP in an attempt to balance a tension, inherent
in many types of air regulations, to ensure adequate compliance, while
simultaneously recognizing that, despite the most diligent of efforts,
emission standards may be violated under circumstances beyond the
control of the source. The EPA must establish emission standards that
``limit the quantity, rate, or concentration of emissions of air
pollutants on a continuous basis.'' 42 U.S.C. 7602(k) (defining
``emission limitation and emission standard''). See, generally, Sierra
Club v. EPA, 551 F.3d 1019, 1021 (D.C. Cir. 2008). Thus, the EPA is
required to ensure that CAA section 112 emissions standards are
continuous. The affirmative defense for malfunction events meets this
requirement by ensuring that, even where there is a malfunction, the
emission standard is still enforceable through injunctive relief. While
``continuous'' standards, on the one hand, are required, there is also
case law indicating that, in many situations, it is appropriate for the
EPA to account for the practical realities of technology. For example,
in Essex Chemical v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973),
the District of Columbia Circuit acknowledged that, in setting
standards under CAA section 111, ``variant provisions'' such as
provisions allowing for upsets during startup, shutdown and equipment
malfunction ``appear necessary to preserve the reasonableness of the
standards as a whole and that the record does not support the `never to
be exceeded' standard currently in force.'' See, also, Portland Cement
Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973). Though intervening
case law such as Sierra Club v. EPA and the CAA 1977 amendments call
into question the relevance of these cases today, they support the
EPA's view that a system that incorporates some level of flexibility is
reasonable. The affirmative defense simply provides for a defense to
civil penalties for violations that are proven to be beyond the control
of the source. By incorporating an affirmative defense, the EPA has
formalized its approach to upset events. In a Clean
[[Page 49509]]
Water Act setting, the Ninth Circuit required this type of formalized
approach when regulating ``upsets beyond the control of the permit
holder.'' Marathon Oil Co. v. EPA, 564 F.2d 1253, 1272-73 (9th Cir.
1977); see, also, Mont. Sulphur & Chem. Co. v. EPA, 2012 U.S. App.
LEXIS 1056 (Jan 19, 2012) (rejecting industry argument that reliance on
the affirmative defense was not adequate). But see Weyerhaeuser Co. v.
Costle, 590 F.2d at 1057-58 (holding that an informal approach is
adequate). The affirmative defense provisions give the EPA the
flexibility to both ensure that its emission standards are
``continuous,'' as required by 42 U.S.C. 7602(k), and account for
unplanned upsets and, thus, support the reasonableness of the standard
as a whole.
Refer to preamble section IX for the NSPS, preamble section X for
the NESHAP and the Response to Comments document for both the NSPS and
the NESHAP, available in the docket, for detailed discussions regarding
these changes.
B. How do the NSPS and NESHAP provide for compliance assurance?
The final rule includes various notification, recordkeeping and
reporting requirements that we believe provide a robust compliance
assurance program, while reducing burden and streamlining requirements.
The EPA also considered a variety of innovative compliance approaches
that could maximize compliance and transparency, while minimizing
burden on the regulated community and regulators. More detailed
information on public comments received and the EPA's responses are
included in sections IX and X of the preamble or in the response to
comments document.
1. Notification, Recordkeeping and Reporting Requirements
For well completions, owners or operators are required to submit an
email notification no later than 2 days prior to each anticipated well
completion. The notification must identify the owner or operator and
provide the American Petroleum Institute (API) well number,
geographical coordinates of the affected wells and the estimated date
of commencement of the flowback period immediately following
hydrofracturing. The owner or operator must keep records identifying
each well completion operation and documenting the portions of the
flowback period when the gas was recovered, combusted or vented.
Annually, owners or operators of all affected facilities under the
NSPS, including gas wells, compressors, pneumatic controllers, storage
vessels and gas processing plants, must report any deviation from the
NSPS requirements during the reporting period. Each annual report must
include a signed certification by a senior company official that
attests to the truth, accuracy and completeness of the report. For
affected gas wells, the report must also identify each well completion
conducted during the reporting period and submit detailed completion
records for each well as part of the annual report.
In the final rule, the recordkeeping and reporting requirements for
well completions also provide a streamlining option that owners and
operators may choose in lieu of the standard annual reporting
requirements. The alternative, streamlined annual report for gas well
affected facilities requires submission of a list, with identifying
information of all affected gas wells completed, electronic or hard
copy photographs documenting REC in progress for each well for which
REC was required and the self-certification required in the standard
annual report. The operator retains a digital image of each REC in
progress. The image must include a digital date stamp and geographic
coordinates stamp to help link the photograph with the specific well
completion operation. The owner or operator is not required to submit
detailed completion records as part of the annual report.
For centrifugal compressors with wet seal systems, the annual
report must include identification of each affected facility
constructed, modified or reconstructed during the reporting period. The
annual report for reciprocating compressors must identify each
reciprocating compressor constructed, modified or reconstructed during
the reporting period. The report also must include, for each affected
compressor, the elapsed time of operation since the most recent rod
packing change as of the end of the reporting period. For affected
pneumatic controllers and storage vessels, the annual report must
identify each affected facility constructed, modified or reconstructed
during the reporting period.
Owners or operators who conduct certain performance tests on
control devices must report results of those tests using the Electronic
Reporting Tool (ERT). Further discussion of reporting of emissions
tests is presented in section VIII.D of this preamble.
NESHAP
The final amendments to 40 CFR part 63, subparts HH and 40 CFR part
63, subpart HHH revise certain recordkeeping requirements.
Specifically, facilities using carbon adsorbers as a control device are
now required to keep records of their carbon replacement schedule and
records of each carbon replacement. We are requiring that owners and
operators that use a manufacturer's tested control device keep records
of visible emissions readings and flowrate calculations and records of
periods when the pilot flame is absent. The final amendments require
records of the date of each semi-annual maintenance inspection be
maintained. Finally, 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 conjunction with the final MACT standards for small glycol
dehydration units, owners and operators of such units are required to
submit an initial notification within 1 year after becoming subject to
40 CFR part 63, subpart HH or by October 15, 2013, whichever is later.
Similarly, in conjunction with the final MACT standards for small
glycol dehydration units in the final 40 CFR part 63, subpart HHH
amendments, owners and operators of small glycol dehydration units are
required to submit an initial notification within 1 year after becoming
subject to subpart HHH or by October 15, 2013, whichever is later.
The final amendments to 40 CFR part 63, subpart HH and 40 CFR part
63, subpart HHH include new requirements for the contents of
Notification of Compliance Status Reports. The owners and operators are
required to include an electronic copy of the performance test results
for the manufacturer's tested control device, if applicable; the
predetermined carbon replacement schedule for carbon adsorbers, if
applicable; and data related to the manufacturer's performance tests
conducted for certain models of control devices, if compliance is being
achieved using the manufacturer's performance tests.
The final amendments to the NESHAP also include additional
requirements for the contents of periodic reports. Each semiannual
report must include a signed certification by a senior company official
that attests to the truth, accuracy and completeness of the report. For
both 40 CFR part 63, subpart HH and 40 CFR part 63, subpart HHH, in the
final amendments, periodic reports are
[[Page 49510]]
required to include periodic test results and information regarding any
carbon replacement events that occurred during the reporting period.
Owners and operators are also required to include in the periodic
reports information regarding any excursions that occur when the inlet
gas flow rate deviates from that identified in the manufacturer's
performance test, and any excursions caused when visible emissions
exceed the maximum allowable duration.
Owners or operators who conduct certain performance tests on
control devices must report results of those tests using the ERT.
Further discussion of reporting of emissions tests is presented in
section VIII.C below.
2. Innovative Compliance Approaches
At proposal, given the number and diversity of sources potentially
affected by the NSPS and/or the NESHAP, we solicited comments on
optional compliance tools that could reduce compliance burden and
enhance transparency. Specifically, we asked for suggestions on: (1)
Registration of wells and advance notification of planned completions;
(2) use of third party verification; and (3) electronic reporting using
existing mechanisms. We received comments on each of the topics above
and have presented summaries of those comments and the EPA's responses
in the Response to Comments document. The commenters were generally
opposed to third party verification. However, one suggestion was a
voluntary random verification program, similar to one used in the past
for gasoline marketing, where operators who participated in this
program potentially could receive lower priority for enforcement
inspections by regulators. Other suggested innovative approaches
include use of social media, including Facebook and Twitter, plus new
technologies such as quick response codes, to provide timely public
notification and access to compliance records for individual wells and
other affected facilities. Other suggestions included use of a
centralized database for industry and public access to compliance
information. Further discussion of these approaches is provided in the
response to comments. While we considered these suggestions, we did not
adopt them in the final rule, for reasons explained further in the
Responses to Comments document.
C. What are the requirements for submission of performance test data to
the EPA?
The EPA must have performance test data to conduct effective
reviews of CAA sections 111, 112 and 129 standards, as well as for many
other purposes, including compliance determinations, emission factor
development and annual emission rate determinations.
As stated in the proposal preamble, the EPA is taking a step to
increase the ease and efficiency of data submittal and data
accessibility. Specifically, the EPA is requiring owners and operators
of oil and natural gas sector facilities to submit electronic copies of
required performance test reports.
As mentioned in the proposal preamble, data entry will be conducted
through an electronic emissions test report structure called the ERT.
The ERT will generate an electronic report which will be submitted to
the EPA's Central Data Exchange (CDX) through the Compliance and
Emissions Data Reporting Interface (CEDRI). A description of the ERT
can be found at http://www.epa.gov/ttn/chief/ert/index.html and CEDRI
can be accessed through the CDX Web site (www.epa.gov/cdx).
The requirement to submit performance test data electronically to
the EPA does not create any additional performance testing and would
apply only to those performance tests conducted using test methods that
are supported by the ERT. A list of the pollutants and test methods
supported by the ERT is available at http://www.epa.gov/ttn/chief/ert/index.html.
The major advantages of electronic reporting are more fully
explained in the proposal preamble.
An important benefit of using the ERT is that the performance test
data will become available to the public through WebFIRE. Having such
data publicly available enhances transparency and accountability.
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 will save industry; state, local and tribal agencies; and the
EPA significant time, money and effort while improving the quality of
emission inventories and, as a result, air quality regulations.
IX. Summary of Significant NSPS Comments and Responses
For purposes of this document, the text within the comment
summaries was provided by the commenter(s) and represents their
opinion(s), regardless of whether the summary specifically indicates
that the statement is from a commenter(s) (e.g., ``The commenter
states'' or ``The commenters assert''). The comment summaries do not
represent the EPA's opinion unless the response to the comment
specifically agrees with all or a portion of the comment.
A. Major Comments Concerning Applicability
1. Activities That Constitute a Modification
Comment: Referring to the definition of ``modification'' in section
111(a)(4) of the CAA, one commenter asserts that a modification occurs
only if two things happen: (1) There must be a ``physical change or
change in the method of operation,'' and (2) the change must result in
an emissions increase.
The commenter states that, in the context of the New Source Review
program, the District of Columbia Circuit Court has opined that
``Congress's use of the word `any' in defining a `modification' means
that all types of `physical changes' are covered'' (New York v. EPA,
443 F.3d 880, 890 (D.C. Cir. 2006)) and that the District of Columbia
Circuit Court has determined that ``the plain language of the CAA
indicates that Congress intended to apply NSR to changes that increase
actual emissions instead of potential or allowable emissions.'' New
York v. EPA, 413 F.3d 3, 40 (DC Cir. 2005).
However, according to the commenter, the Supreme Court has
concluded that the CAA section 111 definition of modification does not
have to have the same meaning under the NSPS and New Source Review
(NSR) programs (Environmental Defense v. Duke Energy Corp., 127 S. Ct.
1423, 1434 (2007)), and, thus, the EPA has latitude within the context
of CAA section 111 to implement different rules regarding
modifications.
The commenter believes, in particular, that the EPA's regulatory
definition of ``modification'' under the NSPS program provides several
categories of activities that alone, are not to be considered
modifications, including ``maintenance, repair, and replacement which
the Administrator determines to be routine for a source category,'' and
``an increase in production rate that can be accomplished without a
capital expenditure.'' 40 CFR 60.14(e). The commenter believes these
provisions reflect the fact that Congress established the NSPS program
for ``new'' sources. According to the commenter, without these
exclusions, even the most minor activities would convert an existing
source into a ``new source.'' The commenter states that the premise
behind characterizing these activities as
[[Page 49511]]
not being ``changes'' is that they all contemplate that the plant will
continue to be operated in a manner consistent with its original design
and, thus, is not a ``new'' facility.
We also received a number of comments objecting to consideration of
recompletion activities \10\ as modifications, claiming that it is a
significant departure from the definition of ``modification'' under the
General Provision at 40 CFR 60.14. Some commenters argue that well
completion expenditures do not meet the regulatory definition of
``capital expenditure'' while others argue that they are maintenance
activities excluded in 40 CFR 60.14 others note that we have not
traditionally regulated temporary ``construction'' activities.\11\
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\10\ At proposal, EPA used the term ``recompletion'' to describe
completions of previously fractured new gas wells that are
refractured at some future date, and we specified that such actions
are considered modifications. In addition, we used the term
``recompletion'' to describe completions of existing wells (i.e.,
those wells that were constructed before August 23, 2011) that
subsequently are fractured for the first time or that are
refractured.
\11\ We disagree with the commenter. Fracturing and refracturing
are not maintenance activities. On the contrary, these are essential
processes that allow production of gas from shale and other
formations, either during the initial development of a well or in
development of new horizons within a previously fractured well. We
also disagree with the characterization that we are regulating
``construction activities.'' Rather we are regulating the emissions
resulting from the physical change.
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Response: In this final rule, the EPA addresses modifications in
the context of well completions and has deleted the proposed definition
of ``modification,'' though the underlying rationale presented in the
proposal remains, and we are providing alternative regulatory text.
Pursuant to this final rule and as discussed below, well completions
conducted on gas wells that are refractured on or after the effective
date of this rule are considered modifications and subject to the NSPS,
with the exception of such well completions that, immediately upon
flowback, use emission control techniques otherwise required for new
wells and satisfy other requirements for gas well facilities, including
notification, recordkeeping and reporting requirements.
As discussed in the proposal, the EPA has chosen to depart from the
definition of modification in 40 CFR 60.14 with respect to regulation
of wells that primarily produce natural gas. As explained in the
proposal and elsewhere in the preamble for this rule, the VOC emissions
from the flowback following refracturing of gas wells are significant,
the EPA has identified cost-effective controls to reduce VOC emissions
during this operating phase, and these controls are required for only a
relatively short time during the well's operating life. The EPA
therefore concludes that it is appropriate for treatment of these
activities to depart from the definition of modification in 40 CFR
60.14 to ensure that emissions from these activities are controlled.
We do not in this package question the broad appropriateness of the
NSPS General Provisions at 40 CFR 60.14. However, as the General
Provisions on modification in 40 CFR 60.14 themselves recognize, they
may not be appropriate in all cases. Given the significant, although
short-term, increase in emissions from flowback caused by refracturing
activities when such activities are not controlled, and the cost-
effective nature of the control on such emissions, we have concluded
that covering these refracturing activities is appropriate even if it
requires departing from the General Provisions' definition of
modification.
Specifically, we are providing in the final rule at 40 CFR 60.5365:
(h) The following provisions apply to gas well facilities that
are hydraulically refractured.
(1) A gas well facility that conducts a well completion
operation following hydraulic refracturing is not an affected
facility, provided that the requirements of Sec. 60.5375 are met.
For purposes of this provision, the dates specified in Sec.
60.5375(a) do not apply, and such facilities, as of the effective
date of this rule, must meet the requirements of Sec.
60.5375(a)(1)-(4).
(2) A well completion operation following hydraulic refracturing
at a gas well facility not conducted pursuant to Sec. 60.5375 is a
modification to the gas well affected facility.
(3) Refracturing of a gas well facility does not affect the
modification status of other equipment, process units, storage
vessels, compressors, or pneumatic controllers located at the well
site.
(4) Sources initially constructed after August 23, 2011, are
considered affected sources regardless of this provision.
As a result of this provision, a modification of a well, defined as
``an onshore well drilled principally for production of natural gas,''
occurs when a well is refractured on or after the effective date of
this rule, except when the owner or operator of a well controls
emissions during the completion operation by the use, immediately upon
flowback, of emission control techniques otherwise required for new
wells, as discussed more below.\12\
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\12\ While we have not done so often, in situations such as
this, where there is a defined set of physical changes that
inevitably lead to an emissions increase, regulatory certainty and
clarity can be provided by, as EPA is doing, providing a categorical
listing of activities that constitute modifications. See, e.g., 40
CFR 60.751 (addressing landfills; definition of modification); 40
CFR 60.100a(c) (addressing refineries; stayed pending
reconsideration).
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Consistency With the Definition of Modification
This provision is consistent with the statutory definition of
modification contained in CAA 111(a)(4).\13\ As discussed in the
proposal, CAA section 111(a)(4) defines a modification based on two
requirements: (1) A physical change and (2) an emissions increase. The
consistency of our approach with these two elements is discussed below.
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\13\ We need not address if New York v. EPA, 443 F.3d 880, 890
(D.C. Cir. 2006) compels the result here. As we explain, in the body
of this preamble our approach is consistent with CAA section
111(a)(4), and we provide a reasonable rationale for adopting the
approach we take here.
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Physical Change
Uncontrolled completion following refracturing of gas wells fits
well within the statutory definition of modification (the refracturing
results in a physical change which causes flowback and an increase in
emissions relative to the emissions level prior to the refracturing).
Accordingly, the NSPS' treatment of modification applies to completions
of hydraulically refractured gas wells.
One commenter contends that recompletion does not constitute
physical change even if there is re-perforation because it is an
expected part of well operation. However, both the CAA and our
regulation define modification to mean ``physical change'' without
providing any qualification to that term, thus indicating that the term
``physical change'' is very broad to include any physical change. The
commenter's interpretation of the term ``physical change'' is without
support.
Emissions Increase
As a result of these physical changes, a multi-day period of
flowback of natural gas, hydrocarbon condensate, water and sand is
necessary to clean up the formation and wellbore prior to production of
gas for sale. This flowback period is characterized by release of
substantial amounts of VOC-containing natural gas and hydrocarbon
condensate that would not have occurred absent the refracturing
operation, thus meeting the second part of the statutory test--an
increase in the amount of emissions.
As discussed in the proposal, EPA's data indicate that uncontrolled
well completions with hydraulic refracturing consistently result in VOC
emissions that were not present prior to such activities. Data in
comments received also confirm that these uncontrolled
[[Page 49512]]
refracturing activities result in significant VOC emissions. Our data
indicate very low VOC emissions from gas wells (2.6 tpy on average) at
the wellhead during ongoing production prior to such activities. In
light of the above, we reasonably conclude that such activities result
in an increase in the amount of VOC emissions and, therefore,
constitute a modification.
We reject the comments suggesting that we should adopt the prior
fracturing activity as the baseline for determining if an emission
increase has occurred.\14\ We note that these comments appear in part
to rely upon a misunderstanding of the EPA's longstanding practice that
the relevant baseline for determining an emissions increase under the
NSPS is not based on the potential emissions profile associated with a
prior physical change or the original construction but rather the
emissions immediately prior to the physical change. See 57 FR 32314,
32330 (July 21, 1992) (explaining that, under CAA section 111(a), an
emission increase is based on current potential emissions rather than
original design capacity). Accordingly, under historical regulations,
the proposed regulatory language and the final rule that ``initial
production volumes may have been higher than subsequent re-completions
or refracturing operations because the formation has been depleted by
production activities'' does not mean that there would not be an
emissions increase. Ongoing emissions during day-to-day production are
very small and are not a function of well productivity, since these
emissions originate from leaking valves and other components that do
not leak more or less as production increases or declines. However,
flowback emissions following refracturing are orders of magnitude
greater than the production phase emissions.
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\14\ One commenter relies on a passage from a proposed, but
never finalized, rule preamble to argue that under the NSPS emission
increase test prechange emissions are based on the highest level
achievable in the 5 years immediately preceding a physical change.
The passage, however, is not addressing the NSPS test generally
applicable to modifications, but, rather, is addressing a specific
regulatory provision applicable to modifications at electric utility
steam generating units (EUSGU). See 70 FR 61081, 61089 (October 20,
2005). Specifically, the preamble discussion is describing 40 CFR
60.14(h), which states that a change at an EUSGU will not be a
modification if ``such change does not increase the maximum hourly
emissions achievable at the unit during the five years prior to the
change.'' See, also, 57 FR 32314, 32330 (July 21, 1992) (adopting 40
CFR 60.14(h) and contrasting the provision with the pre-existing
test).
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Moreover, adoption of a prior fracturing activity as the baseline
for comparison here is inappropriate. The purpose of the refracturing
activity is to increase production from its current level. As explained
above, at least for the short term, VOC emissions from the affected
facility increase as a direct result of the physical change.\15\ That
is, these emissions would not have (and could not have) occurred
without the physical change. Accordingly, we conclude that reliance on
the prior fracturing activity as a baseline is inappropriate.\16\
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\15\ Our data show that the magnitude of ongoing VOC emissions
from a producing gas well is approximately 2.6 tpy or about 14
pounds per day, while the magnitude of VOC emissions is 23 tons over
an average period of 7 days, or about 6,600 pounds per day, during a
completion operation following refracturing. At this time, we do not
have similar data on emissions from oil wells.
\16\ One commenter claims that one cannot determine whether a
given well completion activity qualifies as a modification based on
the proposed definition because it is infeasible to measure the
amount of flowback emission according to the EPA in proposing a work
practice standard. However, nothing in CAA 111(a)(4) and 40 CFR 60.2
requires quantification of the amount of emission increase, only
that there be an increase as a result of the physical change. In
addition, the commenter's argument would appear to apply equally to
any time we set a work practice.
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De Minimis Exception
We recognize that there are reasons to limit the scope of the
modification definition so as to not include certain well-controlled
refracturing activities performed by sources. We recognize that the
approach that we are taking in this final rule differs from the
approach that we have taken in the past, as it excludes certain
emission increases associated with a physical change from constituting
a modification based on the de minimis exception. This exception allows
agency flexibility in interpreting a statute to prevent ``pointless
expenditures of effort'' and has been previously recognized by the
United States Court of Appeals for the District of Columbia Circuit as
an appropriate tool when interpreting the CAA section 111(a)(4)
definition of modification in the context of New Source Review. Alabama
Power Co. v. Costle, 636 F.2d 323, 360 (D.C. Cir. 1979).
Since the inception of the NSPS program, certain emission controls
could be used by a source to avoid having an activity constitute a
modification provided that the controls prevented emissions from
increasing. As the District of Columbia Circuit explained:
Under provisions of the regulations that are not challenged in
this litigation, the operator of an existing facility can make any
alterations he wishes in the facility without becoming subject to
the NSPS as long as the level of emissions from the altered facility
does not increase. Thus the level of emissions before alterations
take place, rather than the strict NSPS, effectively defines the
standard that an altered facility must meet.
Asarco Inc. v. EPA, 578 F.2d 319, 328-29 (D.C. Cir. 1978); see, also,
75 FR 54970, 54996 (September 9, 2010) (``However, sources always have
the option of adding sufficient NOX control to avoid an
hourly emissions increase and avoid thus triggering the modification
provision.''). We have allowed such controls to permit the source to
avoid being considered ``modified'' if the controls fully negate the
emissions increase.
In this case, we are providing that where a source has in place,
and, immediately upon flowback, applies emission controls equivalent to
those required for a new source (as specified in 40 CFR 60.5375(a)(1)
through (4)), the physical change will not constitute a modification
despite the small remaining emission increase. Specifically, well
completions conducted by sources for refractured wells and with the
use, immediately upon flowback, of emission controls equivalent to
those required for new sources will not be considered a modification,
due to the de minimis increase in emissions of such wells using these
controls. Several unique factors justify finding that application of
the de minimis doctrine is appropriate here.
First, to qualify for the exclusion from the definition of
modification the source must be using controls equivalent to those
required were it to trigger the NSPS. As a result, the imposition of
the NSPS would not yield additional regulatory or environmental
benefits. See Environmental Defense Fund, Inc. v. EPA, 82 F.3d 451, 466
(D.C. Cir. 1996). Second, as a result of imposition of controls
emissions are very low in magnitude. This is both with respect to the
size of the increase associated with the physical change and the total
emissions from the unit after the physical change. Third, the emissions
associated with the change, and peak emissions post change, are time-
limited. A well completion is a discrete activity, occurring over a 3-
10-day period on an occasional basis, which may be as infrequent as
once every 10 years. This is different from the type of emitting
activity typically regulated as a modification under NSPS, which would
involve ongoing emissions indefinitely into the future. Further, a
source qualifying for this exception must comply with the recordkeeping
and reporting requirements that are required of new sources.
Accordingly, the increase in emissions from the physical
[[Page 49513]]
change, and the total amount of additional emissions, will be very
small.
We are providing the de minimis exception discussed above to
provide states with flexibility in application of their permitting
authority and resources. Commenters pointed out that a number of state
permitting programs are triggered for sources that are subject to an
NSPS as a result of a modification. The EPA recognizes that states are
the most appropriate entities to determine whether and how sources
should be permitted, and we have concern regarding potential impacts of
this final rule on states' permitting resources. Accordingly, with this
final rule, we intend that states retain the discretion to determine
whether refracturing activities by sources employing control techniques
that are required for new wells will require changes in that source's
permit status.
Clarifying Changes
Although we are not finalizing the proposed definition of
``modification'' for the reasons discussed above, we believe it is
important to address certain comments regarding the proposed definition
in order to clarify the agency's intent as it relates to well
completions. For example, we included ``natural gas'' in the proposed
definition for ``modification'' in recognition that our proposed work
practice requirements for well completions use natural gas as a
surrogate for VOC. We consider natural gas to be an appropriate
surrogate for VOC for well completion activities because our analyses
of data on composition of natural gas at the wellhead indicated that
emissions of natural gas during well completions contain various
chemical species that are VOC. The inclusion of natural gas in the
proposed definition for modification was not an indication that EPA was
proposing natural gas as a pollutant to be regulated, as some
commenters mistakenly thought.
We also received comment objecting to defining ``modification''
based on increase in the ``amount of emission'' instead of ``emission
rate'' as provided in the General Provisions for modifications in 40
CFR 60.14. We had intended but were not clear in our proposed rule that
the definition would apply only to well completions. In the final rule,
we have promulgated the provisions discussed above regarding well
provisions in lieu of the proposed definition for modification to
clarify our intent.
Finally, this provision is intended to address comments suggesting
confusion associated with our proposed definition of ``modification''
and the separate, proposed provision in 40 CFR 60.5420 that a workover
is considered a modification. The second of these provisions is being
removed in light of comments that there is no common understanding of
this term and, as a result, it may be interpreted to cover more than
the fracturing activities the EPA intended to cover.\17\
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\17\ We are not considering ``workovers'' to be modifications
because: (1) They include truly routine activities; (2) in most
instances we would anticipate only a small emissions increase, if
any; and (3) we have no reason to think that these wells differ in
emission profile or control options from non-fractured wells (or
fractured wells after flow back), and accordingly we have not
identified a BSER that would apply following any such modification.
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In summary, as a result of the comments and considerations
discussed above, the final rule provides that well completions
conducted on gas wells that are refractured on or after the effective
date of this rule are modifications and are subject to the NSPS.
However, gas wells that undergo completion following refracturing, with
the use, immediately upon flowback, of emission control techniques
otherwise required for new wells and that satisfy other requirements
for gas well facilities, including notification, recordkeeping and
reporting requirements, are not considered modified and, as a result,
are not affected facilities under the NSPS. This provision is
consistent with the NSPS program's history of allowing sources to use
certain emission controls to avoid having an activity constitute a
modification. In this situation, we consider it appropriate to require
notification, recordkeeping and reporting requirements in order to
ensure that a source is meeting the requirements to avail itself of
this provision. We believe this approach will encourage early use of
REC and will result in 1,000 to 1,500 REC that would not otherwise
occur during the REC phase-in period ending January 1, 2015, discussed
in section IX.B of this preamble.
2. Regulation of Methane and Other Pollutants
Comment: One commenter believes that under CAA section 111, the EPA
must regulate each dangerous pollutant emitted by sources in the oil
and gas source category in more than de minimis quantities for which
controls are available and asserts that the EPA has failed to do so. In
particular, the commenter states that the EPA must regulate methane,
particulate matter (PM), hydrogen sulfide and nitrogen oxides
(NOX) from oil and gas operations. The commenter states that
the EPA's explanation of why it declined to regulate certain pollutants
does not discuss PM or hydrogen sulfide, address the most important
sources of NOX or offer a legal justification for its
failure to regulate methane. The commenter interprets the CAA to mean
that the EPA must, every 8 years, (1) review its standards (as it has
done here), (2) determine whether it is ``appropriate'' to revise them,
including whether it is appropriate to add additional pollutants to the
standards, and (3) if so, revise them accordingly.
Response: In this rule, we are not taking final action with respect
to regulation of methane. Rather, we intend to continue to evaluate the
appropriateness of regulating methane with an eye toward taking
additional steps if appropriate. On November 8, 2010, EPA finalized
reporting requirements for the petroleum and natural gas industry under
40 CFR Part 98, the regulatory framework for the Greenhouse Gas
Reporting Program (GHGRP). Beginning in September 2012, this program
requires annual reporting of greenhouse gases (GHG) from large
emissions sources and fuel suppliers in the United States. Petroleum
and natural gas facilities will report annual methane and carbon
dioxide (CO2) emissions from equipment leaks and venting,
and emissions of CO2, methane and nitrous oxide from
flaring, onshore production stationary and portable combustion
emissions, and combustion emissions from stationary equipment involved
in natural gas distribution. The EPA estimates that the rule will cover
85 percent of the total GHG emissions from the United States petroleum
and natural gas industry with approximately 2,800 facilities reporting.
The data submitted under the GHGRP will provide important information
on the location and magnitude of GHG emissions from petroleum and
natural gas systems and will allow petroleum and natural gas facilities
to track their own emissions, compare them to similar facilities and
aid in identifying cost-effective opportunities to reduce emissions in
the future.
As noted in the proposal, the control measures that the EPA is
requiring for VOC result in substantial methane reductions as a co-
benefit. Over time, collection of data through the GHGRP and other
sources will help EPA evaluate whether it is appropriate to directly
regulate methane from the oil and gas sources covered by this rule. The
EPA will be in a better position to characterize (1) the extent of
methane emissions from these sources that will remain after imposition
of controls
[[Page 49514]]
required by this rule; and (2) whether additional measures are
available and appropriate for addressing such emissions.
With regard to other pollutants, including PM, H2S and
NOX, many of the sources of PM and NOX within the
Crude Oil and Natural Gas Production source category are within the
scope of units covered by other NSPS and will be evaluated in the
context of subsequent revisions of those rules, if appropriate. This
approach is consistent with what the agency articulated when we
promulgated the original oil and gas rules. See 49 FR 2637. For
example, NSPS covering stationary reciprocating internal combustion
engines (40 CFR part 60, subparts IIII and JJJJ) and combustion
turbines (40 CFR part 60, subpart KKKK) regulate emissions of PM and
NOX from sources found in this category. These engines and
turbines are found in a variety of locations in this category including
gathering and boosting stations, natural gas processing plants and
natural gas transmission and storage facilities. In addition, some
mobile source regulations (40 CFR part 1039) cover nonroad engines such
as those used on drilling rigs, electrical generators and hydraulic
fracturing pumps. As we discussed at proposal (see 76 FR 52756) most,
if not all, of the process heaters and boilers used in this category
fall below applicability thresholds for EPA's boiler rules (40 CFR part
60, subparts Db and Dc). Although these smaller heaters and boilers are
generally within the scope of this category, we received no
quantitative data in the public comments on NOX or PM
emissions from these units. Given the broad coverage of the PM and
NOX sources in this category by other NSPS we did not depart
from the approach adopted in 1984 of considering these pollutants in
development of other standards.
Although the NSPS does not provide direct regulation of
H2S, the VOC control requirements in the final rule achieve
reductions of H2S a co-benefit in cases where H2S
is otherwise emitted in the oil and natural gas production segment.
While amine treatment and sulfur recovery are routinely employed both
upstream and at natural gas processing plants to remove H2S
from the natural gas stream, we believe that it would not be reasonable
or cost-effective to require amine units and sulfur recovery for every
emission point in the oil and natural gas production segment. We
received no public comments suggesting other control technologies that
could be applied to control H2S in the field. Such emissions
occur in the field as fugitive emissions at the wellhead and vented
emissions from well completions, storage vessels, pneumatic controllers
and compressors. However, as mentioned above, the VOC control measures
provided in the final rule for well completions, storage vessels,
pneumatic controllers and compressors greatly reduce any H2S
emissions along with the VOC emissions controlled.
3. Expanded Scope of the Source Category
Comment: One commenter states that, in the preamble, the EPA makes
reference to its proposal to significantly expand the scope of oil and
gas operations that would be covered by the new NSPS, and states that
``[t]o the extent that 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'' (citing 76 FR 52745,
August 23, 2011). The commenter is not aware of any authority pursuant
to which the EPA may affect a significant expansion of the category
list merely through the language of the preamble in an NSPS rulemaking.
The commenter states that, in a related context, the CAA requires that
the EPA engage in consultation with state governors and air pollution
control agencies, suggesting that more than a preamble reference is
needed in order to expand the category list and impose NSPS
requirements on the new and unique affected sources addressed in this
rule. See 42 U.S.C. 7411(f)(3). The commenter asserts that the sources
the EPA seeks to regulate are different types of stationary sources
than gas processing plant, and contends that oil and gas production
wells are stationary sources, but are, clearly, not processing plants.
Response: Because EPA has concluded that the currently listed Oil
and Natural Gas source category covers at least those operations in
this industry for which we are finalizing standards, we need not
address what steps the agency must take if expanding a source
category.\18\ As we explained in the preamble to the proposed rule,
when the EPA initially listed this source category, it did so in a
document where it described its listings as broad. 76 FR at 52745.\19\
Contrary to commenters assertions, the EPA has viewed this source
category listing very broadly. Specifically, when promulgating the
first sets of standards of performance for this source category, we
stated that the source category ``encompass[es] the operations of
exploring for crude oil and natural gas products, drilling for these
products, removing them from beneath the earth's surface, and
processing these products from oil and gas fields for distribution to
petroleum refineries and gas pipelines.'' 49 FR at 2637 (emphasis
added). That preamble linked the endangerment finding under CAA section
111(a) to the industry as a whole: ``The crude oil and natural gas
production industry causes or contributes significantly to air
pollution that may reasonably be anticipated to endanger public health
or welfare'' (Emphasis added). 49 FR 2636. The statements above affirm
our conclusion that the currently listed Oil and Natural Gas source
category covers all operations for which we are setting standards. That
the original NSPS's only set standards for a limited set of sources
within the category cannot be taken to imply that other units were not
within the scope of this original listing. See, e.g., Nat'l Lime Ass'n
v. EPA, 627 F.2d at 426 n. 27 (noting that the EPA set standards for
only certain kiln types within the source category). Indeed, the
preamble to the 1984 proposed NSPS rule directly addresses regulation
of wells, concluding that the agency was not setting standards at that
time; not because they were outside the scope of the source category,
but because the agency was unable at that time to identify ``[b]est
demonstrated control technology.'' 49 FR at 2637. As all of the units
that we are regulating fall within the scope of the original listing,
we need not address what steps would be necessary were we to expand the
scope of the listing.
---------------------------------------------------------------------------
\18\ For the same reason, we need not address the comment
claiming that CAA section 111(f)(3) requires that the EPA consult
with state governors before amending CAA section 111(b) listing.
\19\ While not required to do so, we have included the
Background Information Document for the listing rule in the docket
for this rule. We note that those documents shed no additional light
on the scope of the listing beyond our interpretation of the listing
preamble described in the proposed rule.
---------------------------------------------------------------------------
B. Major Comments Concerning Well Completions
1. Applicability and Exemptions
a. Well Exemptions
Comment: One commenter suggests adding ``appraisal wells'' as a
third subcategory of well to be exempt from the REC requirements, and
defines these wells as those drilled in an area where the reservoir has
not been classified for that area as containing proved reserves of
natural gas. According to the commenter, adding this definition and
exemption better reflects the universe of wells for which a gas flow
line system
[[Page 49515]]
will not be available. The commenter adds that it also avoids a
potential problem where a shale play appraisal well system is
effectively compelled to install a flow line system before the wells
are determined to be economically viable, in order to assure compliance
with 40 CFR part 60, subpart OOOO.
Response: The EPA recognizes that a flow line at the well pad is a
necessary precondition to capture flowback gas for emissions control so
that the REC process has an outlet for the captured gas. However, the
EPA does not agree that appraisal wells need to be exempt. Appraisal
wells are drilled and then logged to assess productivity. If well logs
indicate that the well is productive, then fracturing will be
performed, and the cost to fracture, complete and produce the well,
including installing a flow line, will be incurred. If the well logs
indicate the well is not economically productive, then no fracturing
occurs and the NSPS does not apply. The EPA, therefore, believes it is
reasonable to require appraisal wells that are hydraulically fractured
to comply with Subcategory 3 rule requirements.
b. Threshold for Low Pressure (Low Volume) Gas Wells and Wells with Low
or No VOC Emissions
Comment: One commenter expresses support for the REC requirements
and urges the EPA to limit the number of well completions exempted from
the requirements as much as possible. Several commenters contend that
not all well completions can be conducted successfully under a
requirement to flow back to the flow line, since the imposition of the
flow line backpressure may reduce the flowback gas velocity
sufficiently so that it is not energetic enough to clean up the well of
liquid and sand. One commenter recommends that any well whose reservoir
pressure (measured at the wellhead immediately after perforation) is
less than 4 times (in absolute units) the line pressure measured at the
flow meter, would be exempt from any requirement to flow to sales
during the flowback period. According to the commenter, variability in
reservoir and line pressures across the United States makes setting a
specific pressure threshold difficult.
Response: The EPA has established three subcategories of wells in
response to public comments, as described above. One of those
categories comprises non-wildcat and non-delineation low pressure gas
wells. Low pressure gas wells are defined as wells with reservoir
pressure and vertical well depth such that 0.445 times static reservoir
pressure (in pounds per square inch absolute (psia)) minus 0.038 times
the vertical well depth (in feet) minus 67.578 psia is less than the
flow line pressure at the sales meter. Thus, wells above this pressure
differential must implement REC, while wells below this pressure
differential are required to route emissions to a completion combustion
device.
The EPA solicited comment in the proposed rule on situations where
REC may be infeasible and criteria and thresholds for distinguishing
well completion operations in those situations from others where REC is
feasible. As noted above, several commenters highlighted the technical
issues that prevent an operator from implementing an REC on a low
pressure gas well, which is the inability to attain a gas velocity
sufficient to clean up the well when flowing against the flow line
backpressure. Based on this information, the EPA agrees that a pressure
differential threshold is reasonable and addresses the technical
limitations of low pressure gas wells to produce to the flow line
during completion.
As noted above, a commenter recommended specific approaches to
developing a pressure threshold, including specifying that any well
whose reservoir pressure is less than 4 times (in absolute units) the
line pressure measured at the flow meter would be exempt from any
requirement to flow to the flow line during the flowback period. This
recommendation is based on a flowing bottom hole to reservoir pressure
ratio of 1:2 and a line pressure to flowing bottom hole pressure of
1:2. The EPA concurs with the commenter that flowing bottom hole
pressure can be represented as half of the reservoir pressure for this
rule. The EPA disagrees with the commenter that line pressure can be
represented as half of the flowing bottom hole pressure for this rule
since this pressure relationship can be more accurately determined
using the Turner equation for liquids unloading from a well paired with
models relating fluid velocity to pressure drop. Therefore, the EPA has
modeled a worst-case pressure drop factor between the line pressure and
flowing bottom hole pressure and has established a pressure threshold
using this factor and the 1:2 factor for flowing bottom hole pressure
to reservoir pressure. The result of this modeling is the equation
discussed above in the definition of low pressure gas wells.
As discussed in the proposal preamble, potential control options
are REC with combustion or a completion combustion device alone.
Because REC may not always be technically feasible for wells that fall
below the pressure threshold, the EPA has determined that the BSER for
reducing VOC emissions for this subcategory of wells is a completion
combustion control device. However, the EPA encourages the use of REC
with combustion should that be a viable option for any well within this
subcategory. Therefore, in the final rule, for non-wildcat and non-
delineation wells with a pressure drop below the differential described
above, the EPA requires the use of either a completion combustion
device or REC with combustion to control gas not suitable for entering
the flow line.
Comment: Several commenters address parameters for defining which
well completions would be subject to REC requirements. Commenters
request that the EPA exempt wells with low VOC concentrations from the
REC requirements and not issue the proposed standards before
reconsidering the emissions estimates. One commenter suggests that the
EPA exempt hydraulically fractured natural gas horizontal wells with de
minimis VOC concentrations because the cost per ton of VOC reductions
is extremely high for these wells and the emissions from the combustion
of the produced gas could worsen ozone formation in the area.
Commenters also provide, as examples, some wells with low or no VOC as
support for exempting wells with a low VOC content or for exempting
certain classes of wells such as coal bed methane. Several commenters
contend that coal bed methane wells have low VOC, while several other
commenters contend that coal bed methane wells have no VOC. Some
commenters provide examples of coal bed methane wells with low VOC or
no VOC, and one commenter provides an example of a shale gas well with
no VOC.
Response: The EPA acknowledges that the VOC concentration in
natural gas can vary across wells and reservoir types such as coal bed
methane (CBM), shale and tight sands. However, the information provided
in the comment is insufficient for the EPA to determine that any
specific class of wells, or wells with VOC concentration below a
specific threshold, would not be cost-effective to regulate, as the
commenters recommend. For example, several commenters contend that CBM
wells have low or no emissions. In response to comments received, the
EPA assessed the VOC content of CBM wells, including a review of the
gas composition data presented in the gas
[[Page 49516]]
composition memo\20\ available in the docket and in an article\21\ by
the United States Geological Survey. The VOC concentrations among CBM
wells will vary and are not always low. The limited CBM data submitted
by the commenter, while suggesting low-VOC concentrations at some CBM
wells, is not to the contrary. Accordingly, we conclude that it would
be inappropriate to provide a categorical exclusion for such wells.
---------------------------------------------------------------------------
\20\ Memorandum from Brown, Heather, EC/R Inc., to Moore, Bruce,
EPA/OAQPS/SPPD, Composition of Natural Gas for use in the Oil and
Natural Gas Sector Rulemaking, July 28, 2011. Docket ID No. EPA-HQ-
OAR-2010-0505-0084.
\21\ Rice, Dudley, Composition and Origins of Coalbed Gas, U.S.
Geological Survey, Denver, Colorado.
---------------------------------------------------------------------------
We also have determined that providing a low-VOC concentration
exclusion would be inappropriate, both because the submitted data do
not support such an exclusion (they do not demonstrate that such
circumstances are frequent) and because of implementation concerns.
Specifically, even if such a VOC concentration threshold described
above can be determined, to ensure compliance with the rule, an
operator would have to determine with certainty before production,
whether a particular well was going to be above or below the threshold
in order to mobilize the necessary capture equipment and secure a flow
line, etc. This would require the operator to determine the reservoir
composition, e.g., the gas composition prior to separation, in advance
of the well completion (i.e., the determination of whether the well
would be subject to the NSPS would have to be performed before the
information on which to base such a determination would be available).
Although nearby existing wells could potentially provide some
indication of the general VOC content of the gas from the future well
in question, there would be no assurance of certainty. In addition, the
operator would need to certify that the reservoir sample is going to
stay consistent and representative of the gas stream throughout the
full completion process through multiple gas composition analyses.
Taking into account the variability in VOC concentrations across
reservoir types, the EPA's cost analysis illustrates that these
requirements are cost-effective, especially when taking into account
the gas savings. Compliance with a VOC concentration threshold-based
rule for well completions could actually increase the burden to the
operator by requiring numerous compositional analyses to demonstrate
compliance with the rule.
c. Definition of Gas Well
Comment: Several commenters mentioned that the proposed definition
of ``gas well'' was unclear due to the term ``principal production''
used in describing what the well produces. One commenter requests that
the definition of gas well be modified to be each respective state's
definition of gas well. The commenter states that, by doing this, the
EPA would eliminate any confusion associated with having to apply
different criteria (NSPS versus state regulations) for how to define a
well-type in assessing the applicability of the rule.
Response: In response to comments requesting further clarity in the
definition, the EPA has revised the definition. The proposed definition
was ``Gas well means an onshore well, the principal production of which
at the mouth of the well is gas.'' In the final rule, in response to
the comments we received, the EPA has revised the definition to exclude
the phrase ``at the mouth of the well is gas.'' Based on this revision,
the definition for the final rule is ``Gas well or natural gas well
means an onshore well drilled principally for production of natural
gas.''
EPA's intent in setting standards for completion of hydraulically
fractured gas wells is to require reduced emissions completions for
wells where infrastructure is generally present to get recovered
natural gas to market. Our understanding is that owners and operators
plan their operations to extract a target product and evaluate whether
the appropriate infrastructure is available to ensure their product has
a viable path to market before completing a well. We expect that the
final rule will result in control of hydraulically fractured gas wells
drilled in the four formation types generally accepted as gas-producing
formations: (1) High-permeability gas, (2) shale gas, (3) other tight
reservoir rock or (4) coal seam. We believe that the wording changes
made to the definition of ``gas well'' clarify the intent so that
implementing agencies and industry will not be burdened with complex
applicability determinations.
With respect to using State gas well definitions, basing
applicability on different definitions from State to State could
introduce inconsistencies that are counter to the goal of nationwide
regulation. We believe the NSPS, being a national rule, should contain
a single definition applicable nationwide. However, states may choose
to use a definition more expansive than our definition for their
programs.
Comment: One commenter states that, based on the EPA's discussion
in Section 4 of the Technical Support Document (TSD), it appears the
EPA's intent is to require reduced emissions completions only for
natural gas wells. The commenter supports that the EPA applied reduced
emissions completions only to natural gas wellhead facilities and
excluded oil wellhead facilities and other types of gas wells which
have little or no VOC emissions. The commenter states that, as shown on
page 4-13 on Table 4.4, Nationwide Baseline Emissions from Uncontrolled
Oil and Gas Well Completions and Recompletions, of the TSD, there are
only 134 tpy of VOC emissions from oil well completions and
recompletions for the entire United States, which is not worth
regulating.
One commenter recommends the following revision: ``Gas well means a
well, the principal production of which at the mouth of the well is
[add: hydrocarbon gas, not CO2] * * * 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.'' One commenter proposes the
following revision: ``Gas well means a well, [DELETE the principal
production of which at the mouth of the well is gas] completed for
production of natural gas from one or more gas zones or reservoirs.
Such wells contain no completions for the production of crude oil.''
The commenter also proposes the following revision: ``Gas well means a
well [STRIKETHROUGH: the principal production of which at the mouth of
the well is gas.] [ADD TEXT: completed for production of natural gas
from one or more gas zones or reservoirs. Such wells contain no
completions for the production of crude oil.]''
Response: Although some wells drilled in crude oil formations may
produce associated gas along with the oil, without a gas infrastructure
present, the EPA does not have sufficient data on VOC emissions during
completion of hydraulically fractured oil wells to set standards for
these operations at this time.\22\ As a result, the final rule will not
affect drilling of oil wells.
---------------------------------------------------------------------------
\22\ In the proposed rule, we briefly assessed well completions
of hydraulically fractured oil wells and did not believe that either
REC or a completion combustion device is cost effective for reducing
VOC emissions from such operations. We note, however, that this
brief assessment of oil wells in the proposed rule was based on
limited information at the time and that more information is needed
for us to fully evaluate the VOC emissions and control options for
these operations.
---------------------------------------------------------------------------
[[Page 49517]]
d. Availability of Infrastructure to Convey Gas to Market
Comment: Various commenters have asserted that, in some cases, REC
cannot be performed on some wells because there is no gathering line
available to convey gas produced during the completion flowback period.
Response: As explained above, it is our understanding that owners
and operators plan their operations to extract a target product and
evaluate whether the appropriate infrastructure access is available to
ensure their product has a viable path to market before completing a
well. However, in the standards for gas well affected facilities, the
provisions of 40 CFR 60.5375(a)(1) through (4) apply to all fractured
gas wells that are not exploratory wells, delineation wells or low
pressure wells. These standards require that the well completion
flowback be conducted using a combination of collection (i.e., REC),
combustion and venting, depending on the characteristics of the
flowback material and feasibility of routing the gas to a collection
system to be conveyed to market. Section 60.5375(a)(3) provides:
``You must capture and direct flowback emissions that cannot be
directed to the flow line to a completion combustion device * * *''.
We believe that owners and operators of gas wells subject to 40 CFR
60.5375(a) that require REC for a portion of the flowback period will
exercise due diligence in coordinating the completion event with
availability of a flow line to convey captured gas to market. However,
there may be cases in which, for some reason, the well is completed and
flowback occurs without suitable flow line available. In those isolated
cases, we believe 40 CFR 60.5375(a)(3) provides for gas not being
collected and instead combusted or vented pursuant to that section.
e. Fracturing of Wells Using Nitrogen and Carbon Dioxide
Comment: One commenter suggested that wells that are fractured
using nitrogen or CO2 should be exempt from the NSPS but did
not provide supporting rationale. Other commenters expressed concern
that inert gases such as nitrogen are not flammable, making compliance
with the combustion provisions of the NSPS impossible.
Response: We believe that the standards for well completions
adequately address the concerns expressed by operators using nitrogen
and/or CO2 for fracturing. We provided in the proposed rule,
and further clarified in the final rule, that these standards require
that the well completion flowback be conducted using a combination of
collection (i.e., REC), combustion and venting, depending on the
characteristics (including flammability) of the flowback material and
feasibility of routing the gas to a collection system to be conveyed to
market. Both the proposed and final rules express our intent to require
REC only where there is salable quality gas to the gather line. See 76
FR 52800 and 40 CFR 60.5375(a)(2) of the final rule.
Section 60.5375(a)(3) in the final rule provides: ``you must
capture and direct flowback emissions that cannot be directed to the
flow line to a completion combustion device, except in conditions that
may result in a fire hazard or explosion, or where high heat emissions
from a completion combustion device may negatively impact tundra,
permafrost or waterways. Completion combustion devices must be equipped
with a reliable continuous ignition source over the duration of
flowback.''
Under this provision, operators who employ energized fracturing
using inert gases and cannot route the flowback gas to a collection
system because of poor gas quality must direct the flowback to a
completion combustion device with a continuous ignition source.
Although part of the flowback gases directed to the combustion device
would not be flammable, the ignition source will ignite the flammable
portion of the flowback, including VOC. Therefore, the presence of
inert gases such as nitrogen and CO2 in the flowback gas has
no bearing on the VOC reduction we expect to achieve through the NSPS
or on compliance with provisions of the final rule.
2. Rule Should Not Prescribe Equipment
Comment: Several commenters suggest revising 40 CFR 60.5375(a)(2)
equipment requirements to be less prescriptive, especially in cases
where use of specified or all listed equipment may not be necessary,
and to provide flexibility to include newly developing technology.
Other commenters assert that language in 40 CFR 60.5375(a)(1) and (2)
stating that source owners or operators should ``minimize the emissions
associated with venting of hydrocarbon fluids and gas'' and that
``[a]ll salable gas must be routed to the gas gathering line as soon as
practicable'' is vague and recommended a requirement that facility
owners follow a Best Management Practice (BMP) plan that the EPA could
develop, informed by the Natural Gas STAR program.
Response: The EPA agrees that prescribing specific equipment to
accomplish a reduced emissions completion is not necessary and has
revised the rule language to not prescribe specific equipment. The
operational standards provided in the NSPS allow the operator
flexibility to perform the REC using equipment and practices best
determined by the operator. As a result, we believe that a BMP plan
developed by the EPA would not provide a higher degree of emissions
control and could hinder innovation.
3. Availability of Equipment and Trained Personnel
Comment: Commenters state that the supply of REC equipment and
personnel is insufficient to meet the requirements of the proposed
rule, applied nationally. According to commenters, proper surface
equipment, collection infrastructure and qualified personnel are not
readily available; they assert that this equipment is fairly
specialized, the shops licensed to make it are limited and some of the
components require a long lead time. For these reasons, commenters
indicate that compliance by the issuance date of the rule would be
unrealistic and that the EPA should provide a longer compliance period.
Response: Based on information submitted by commenters, we have
reason to believe that, currently, there is already significant demand
for REC equipment. For example, Colorado, Wyoming, the City of Fort
Worth, Texas, and the City of Southlake, Texas, require REC under
certain conditions. Additionally, public comments, reports to the EPA's
Natural Gas STAR Program and press statements from companies indicate
that some producers implement REC voluntarily, based upon economic and
environmental objectives. If REC were to be immediately required of all
well completions, NSPS would place significant additional demands on
REC equipment supply and experienced personnel.
As the near-term supply of REC equipment and trained personnel will
be insufficient to meet the new national demand for equipment and
labor, immediate compliance with the REC requirements could be
impossible, potentially causing producers to delay well completions
until appropriate equipment and labor are available. Resulting delays
in well completions while awaiting equipment availability could cause a
decrease in the nationwide natural gas supply and would drive up the
cost of completions doing REC. It is not the EPA's intent to set in
motion a series of events through this rule that has the potential to
affect
[[Page 49518]]
the natural gas supply and increased cost of REC would undermine our
BSER analysis. Accordingly, it is important that the EPA consider the
availability of REC equipment and personnel in its BSER analysis.
Through EPA and industry events and collaborative studies, the EPA
has interacted with operating companies that have extensive experience
implementing REC. In particular, the EPA developed a detailed study
\23\ on REC in collaboration with service providers. Based on this
experience, the EPA has gained extensive information on this
technology. Despite these efforts, the EPA is not aware of any
quantitative information on the current and future supply of workers
trained in REC techniques.
---------------------------------------------------------------------------
\23\ Available at: http://www.epa.gov/gasstar/documents/reduced_emissions_completions.pdf.
---------------------------------------------------------------------------
The EPA received data on the current and future supply of REC
equipment. According to one commenter, about 300 REC units are in use
today, with the ability to process about 4,000 wells per year, and
1,300 additional units would be required to perform 20,000 REC per
year. About 1,600 units performing 20,000 REC/year implies a REC
productivity rate of about 12.5 REC/year/unit, or roughly each unit
performing one REC per month, on average.
The NSPS proposal estimated 9,300 REC performed for new natural gas
well completions and 12,200 REC performed for existing natural gas well
completions following refracturing would be required, in addition to
those already required by state regulations. In the analysis supporting
the final rule, the EPA revised estimates show 11,403 hydraulically
fractured and 1,417 hydraulically refractured natural gas well
completions will be performed in a representative year, which includes
completions in states which currently have REC requirements. The
revised estimate also reflects a change in the refracture frequency of
existing wells from 10 percent to 1 percent based on information
provided by commenters. Of the total hydraulically fractured well
completions, the EPA estimates that about 11,300 REC will be required
nationally on the basis of the final rule's provisions for wildcat
(exploratory) and delineation wells, flowback gas pressure and natural
gas well completions conducted on existing gas wells that are
subsequently fractured or refractured. This estimate excludes REC
required by state regulations.
Assuming a REC unit performs 12.5 REC/year, as is asserted by the
commenter, about 900 units would be required. This implies a current
shortfall of about 600 units, based upon the numbers and assumptions
provided by the commenter. The commenter states that industry can
deliver about 50 units per quarter, after a 1-year build-up period.
Given that the EPA does not have an alternative estimate of the number
of REC units industry can produce per year, we adopt the estimate of 50
units per quarter for this analysis, although the EPA disagrees with
the assumption that a 1-year build-up period is required. Using the
commenter's assumptions, it would take about 4.25 years to meet demand.
This scenario is depicted in Scenario A in Table 6 below, assuming
compliance is initiated at the beginning of the second quarter, 2012,
and the industry begins delivering 50 units per quarter roughly 1 year
after the compliance date.
Surveys conducted by one commenter indicate that nine companies
expect to perform more REC than the current stock is capable of. Given
this growing demand, it is reasonable to assume industry can deliver
units during the build-up period of the first year of implementation,
which would reduce the time required to meet full demand another year
to a total of about 3.25 years (Scenario B).
The EPA also assessed whether the productivity of equipment in use
could be higher than the 12.5 REC/year/unit derived from the comment,
and the potential impact of such increase on the equipment supply. The
EPA estimated that flowback periods will typically be 3 to 10 days with
7 being a reasonable average. Therefore, because it is likely that a
REC unit could be moved to another well site and be in operation in
less than 20 to 27 days, it is reasonable to conclude that each REC
unit can perform more than 12.5 REC/year.
If the utilization rate of REC units is increased gradually from
performing 12.5 REC/year/unit to 14 to 18 REC/year/unit, the time
required to build the supply of REC units decreases (Scenarios C-G). As
Table 6 shows, each 1 REC/year/unit increase reduces the build-up time
by about 1 quarter. As is shown in Scenarios C and G, increasing the
utilization rate of REC to 14 to 18 REC/unit/year with industry
supplying new units beginning with the compliance date would provide
between 1.75 and 2.75 years for full build-out of the REC unit supply
by the beginning of calendar year 2015.
Table 6--REC Unit Supply Analysis
----------------------------------------------------------------------------------------------------------------
Scenario A B C D E F G
----------------------------------------------------------------------------------------------------------------
RECs Required...................... 11,301 11,301 11,301 11,301 11,301 11,301 11,301
RECs/year/unit..................... 12.5 12.5 14.0 15.0 16.0 17.0 18.0
Units Needed....................... 904 904 807 753 706 665 628
----------------------------------------------------------------------------------------------------------------
Stock in Existence (assume industry can build 50 units/quarter; assuming industry starts with 300 units);
compliance begins approximately at the end of the second quarter, 2012.
----------------------------------------------------------------------------------------------------------------
2012 (Q1).......................... 300 300 300 300 300 300 300
2012 (Q2).......................... 300 300 300 300 300 300 300
2012 (Q3).......................... 300 350 350 350 350 350 350
2012 (Q4).......................... 300 400 400 400 400 400 400
2013 (Q1).......................... 300 450 450 450 450 450 450
2013 (Q2).......................... 300 500 500 500 500 500 500
2013 (Q3).......................... 350 550 550 550 550 550 550
2013 (Q4).......................... 400 600 600 600 600 600 600
2014 (Q1).......................... 450 650 650 650 650 650 650
2014 (Q2).......................... 500 700 700 700 700 700 .........
2014 (Q3).......................... 550 750 750 750 750 ......... .........
2014 (Q4).......................... 600 800 800 800 ......... ......... .........
2015 (Q1).......................... 650 850 850 ......... ......... ......... .........
[[Page 49519]]
2015 (Q2).......................... 700 900 ......... ......... ......... ......... .........
2015 (Q3).......................... 750 950 ......... ......... ......... ......... .........
2015 (Q4).......................... 800 ......... ......... ......... ......... ......... .........
2016 (Q1).......................... 850 ......... ......... ......... ......... ......... .........
2016 (Q2).......................... 900 ......... ......... ......... ......... ......... .........
2014 (Q3).......................... 950 ......... ......... ......... ......... ......... .........
----------------------------------------------------------------------------------------------------------------
Because of uncertainties in the supply of equipment and labor over
the near-term, and based on our analysis described above, the EPA
concludes that REC may not always be available through 2014. Therefore,
during this period, the BSER for well completions is to combust
completion emissions. REC with combustion as an alternative to
combustion is permitted by the rule so that facilities that are able to
obtain REC equipment may still capture completion emissions using a
REC. After January 1, 2015, capturing completion emissions using a REC
will be considered BSER. This period will permit the companies
producing REC units to increase production to levels sufficient to meet
new demand. In addition, because more REC will be performed as a result
of this rule, the EPA believes that producers will take advantage of
scale economies and use REC units at a higher rate of productivity than
the rate implied by comments received.
The EPA believes that the NSPS, as finalized, will minimize the
risks of producers slowing well completion-related activities to obtain
appropriate equipment and labor. While there would be NOX
formation as a result from the additional combustion of completion
emissions during the phase-in period, VOC emissions reductions would be
maintained because completion emissions will be either combusted or
captured. The EPA maintains that the benefit of the VOC reduction
during the phase-in period far outweighs the secondary impact of
NOX formation during pit flaring. The phase-in period would
also minimize the possibility that the cost of REC equipment and labor
increases over the near-term, enabling producers to better plan
efficient use of existing and new capital and labor, and providing
additional time for innovation in REC technologies and/or practices. We
believe this period provides ample time for this technology to be built
and available for use.
At the same time, for wells undergoing recompletions during the
period prior to January 1, 2015, the terms of 40 CFR 60.5365(h), which
specify that ``[a] gas well facility that conducts a well completion
operation following hydraulic refracturing is not an affected facility,
provided that the requirements of section 60.5375 are met,'' may
provide an additional incentive for producers to use REC units prior to
January 1, 2015, if they can obtain appropriate equipment and labor.
Also, considering the requirement in some states that any source
subject to a federal NSPS must get a state minor source air permit, we
anticipate that the desire to avoid even short term delays caused by
state permitting, as well as the associated costs, will serve as an
incentive for the use of REC during well completion operation following
hydraulic refracturing, including operations prior to January 1, 2015.
Furthermore, as January 1, 2015, approaches it is highly likely that
providers of REC equipment and related services will be increasing
availability of such equipment and services in ways that benefit supply
and price. For these reasons, the EPA anticipates that during the
period between promulgation and January 1, 2015, between 1,000 and
1,500 wells will be recompleted with REC units, notwithstanding the
requirements of 40 CFR 60.5375(a) and the combustion option they
provide.
4. Cost and Emissions Calculations
Comment: Some commenters request the EPA to fully explain or
reconsider the 10-percent rate of refracturing of wells.
Response: In response to comment, the EPA has reevaluated the
assumption that, on average, each fractured gas well is re-fractured
every 10 years, which equates to approximately 10 percent of fractured
gas wells being re-fractured each year, based on drilling and re-
fracture records from an industry representative. Based on its review
of the comment, including references noted in the comment and other
information available to the agency, the EPA concluded that it had
overestimated the re-fracturing frequency. The information reviewed by
the EPA, which, altogether, represent over 20,000 gas wells over
multiple years, some as far back as 2000, indicate that the annual
recompletion frequency can be as low as 0.1 percent and as high as 0.8
percent. Based on this information, the EPA has revised its estimate of
re-fracturing frequency from 10 percent to 1 percent of fractured gas
wells per year. The EPA rounded the figures provided by the companies
to reflect the uncertainty in the data.
5. Definition of Affected Facility
Comment: Several commenters assert that a well completion is
different from a well workover and should be better defined in the
rule.
Response: Based on the comments received, the EPA acknowledges that
the term ``workover'' is a general term that may have a number of
different meanings. Based on the various definitions of the term
provided by the commenters, we realize that workover may be interpreted
to include routine maintenance activities that we did not intend to
cover under the rule and which result in no increase in emissions.
Therefore, in the final rule we have revised the definition of ``well
completion operation'' to exclude the term ``workover'' and, instead,
include the phrase ``with hydraulic fracturing.''
C. Major Comments Concerning Pneumatic Controllers
1. Definition of Affected Facility
Comment: Some commenters request that the EPA consider excluding or
exempting emergency and/or safety system devices (such as a pilot
operated pressure relief valve). According to one commenter, safety
system devices typically do not emit gas unless there is an emergency,
have a near-zero VOC-level static state and, if regulated, could be
replaced by substandard, cheaper technology of spring operated valves
which would create much more leakage of gas into the environment.
With regard to emergency situations, another commenter argues that
the proposed standards that apply to pneumatic controller affected
facilities (40 CFR 60.5390(b)) could inhibit safe plant operation
during an emergency because they require that each pneumatic controller
located at a natural gas processing plant have zero
[[Page 49520]]
natural gas emissions. According to the commenter, a gas-powered
controller is a reliable alternative for safe plant operation during
emergencies, and the commenter suggests that the final rule include an
exception to allow gas plants to use natural gas-driven pneumatic
controllers for emergency plant shutdown and subsequent startup.
With regard to high-bleed pneumatic controllers, several commenters
request that the EPA further explain when the use of high-bleed
pneumatic controllers is allowed and provide specific examples of
exemptions. The commenters suggest exemptions that address situations
such as those where the natural gas includes impurities that could
increase the likelihood of fouling a low-bleed pneumatic controller,
such as paraffin or salts; where weather conditions could degrade
pneumatic controller performance; during emergency conditions; where
flow is not sufficient for low-bleed pneumatic controllers; where
electricity is not available; and where engineering judgment recommends
their use to maintain safety, reliability or efficiency. Several
commenters request that the EPA provide additional information about
how to demonstrate that the use of high-bleed pneumatic controllers is
predicated, as stated in proposed 40 CFR 60.5390(a). The commenters
suggest that this exemption is very vague, will allow for excessive
emissions and is not enforceable.
Response: The EPA included in the proposed rule exemptions from the
NSPS to allow the use of a controller with a natural gas bleed rate
greater than 6 scfh due to functional needs. These exemptions include,
but are not limited to, response time, safety and actuation of valves.
These functional exemptions to the requirement address the commenters'
concerns of safety, emergency and otherwise non-routine situations that
require the use of a controller with a natural gas bleed rate greater
than 6 scfh. In response to comments regarding vagueness of the
proposed exemption, the EPA revised this exemption provision in the
final rule. We believe the provision in the final rule clarifies the
scope of this exemption.
Comment: Several commenters express concerns with the proposed
rule's treatment of various types of pneumatic devices and controllers.
One commenter requests that the EPA clarify in 40 CFR part 60, subpart
OOOO that intermittent bleed pneumatic devices are not affected
sources. Another commenter asserts that continuous low-bleed
controllers that replace existing continuous low-bleed controllers
should not be ``affected facilities.'' According to this commenter,
some designed high-bleed devices may be isolated from the gas pressure
with a valve and operated manually on an intermittent basis. The
commenter wants clarification in the rule that will allow an operator
to use a high-bleed device if it is operated in a manner that keeps its
emission levels less than 6 scfh.
One commenter requests that the EPA clarify in the final rule that
the distribution segment and self-contained devices that release gas to
a downstream pipeline instead of to the atmosphere are exempt. Another
commenter argues that no-bleed pneumatic devices have zero emissions
and, thus, should not be included in the proposed rule.
One commenter discusses the use of solar-powered controllers, fuel-
cell powered controllers and mechanically-controlled devices in remote
locations as an alternative to natural gas where grid electricity is
not available. This commenter also recommends that the EPA set a zero
emissions standard based upon no-bleed devices wherever electricity
(either from a grid or from field power sources) is available within a
reasonable distance from the facility and suggests that the EPA could
establish an exemption to no-bleed devices where low-bleed devices are
necessary because no-bleed devices cannot be feasibly installed.
Another commenter states the definition of ``pneumatic controller''
is unclear and should be revised.
Response: In the final rule, the EPA has revised the definition of
``affected facility'' for pneumatic controllers in the production
segment \24\ to address a number of the comments described above.
Specifically, for pneumatic controllers at gas processing plants where
the standard is zero bleed rate, we have defined the affected facility
as a continuous bleed natural gas-driven pneumatic controller. For
other areas in the production segment (i.e., excluding gas processing
plants), where the standard is a bleed rate of 6 scfh or less, we have
defined the affected facility as a continuous bleed natural gas-driven
pneumatic controller operating at a bleed rate greater than 6 scfh. By
defining the pneumatic controllers affected facilities to be continuous
bleed and gas-driven, we clarify that the NSPS does not apply to
intermittent bleed devices, no-bleed pneumatic devices (by design),
self-contained devices and devices driven by instrument air. The
revised definitions also exclude from the NSPS coverage owners and
operators who are already using (including replacement) pneumatic
controllers that meet the applicable standards, thus, relieving them
from the cost and other burdens related to compliance.
---------------------------------------------------------------------------
\24\ The NSPS does not cover pneumatic controllers in the
distribution segment. The EPA did not address those controllers in
the proposed rule. Although the EPA had proposed standards for
pneumatic controllers in the transmission and storage segment, for
reasons explained in section IX.C.2 of this preamble, the EPA did
not include such standards in the final rule.
---------------------------------------------------------------------------
Regarding the comments related to solar-powered controllers, fuel-
cell powered controllers, mechanically-controlled devices and no-bleed
devices wherever electricity is available, we considered these types of
devices in the BSER analysis, as discussed in the TSD. Any such
controller system would require a backup system (consisting of at least
an electrical generator) to operate the controllers when the primary
system was inoperable. When considering the cost of the backup system,
these options were not cost-effective. We, therefore, do not believe
that they are BSER for reducing VOC emissions from pneumatic
controllers where grid electricity is not available. We also decline to
set a zero emission standard ``wherever electricity * * * is available
within a reasonable distance,'' as a commenter suggests. We have no
information, nor has the commenter provided any, on how to determine
the suggested ``reasonable distance.''
Comment: Several commenters request an exemption for all affected
facilities handling gas with less than 10-percent VOC content by
weight. Some commenters offer suggestions for such exemption, such as
requiring recordkeeping of the gas VOC content in order for a facility
to maintain the exemption.
One commenter believes that the EPA should delete the pneumatic
controller requirements because most of the gas emitted is methane, and
there is little VOC emission reduction benefit. Another commenter
suggests limiting applicability to pneumatic controllers at natural gas
processing plants or upstream of processing that exceeds a defined VOC
threshold.
Several commenters opine that pneumatic device definitions and
applicability should be based on VOC emissions, not natural gas as a
surrogate. Commenters assert that the 6 scfh high-bleed/low-bleed
threshold value is unsupported, that natural gas VOC content varies
widely and that, in most cases, unconventionally produced CBM and shale
gas have little, if any, measurable VOC.
Several commenters also wanted to exclude pneumatic controllers
driven by a specified percentage of VOC.
[[Page 49521]]
According to the commenters, regulating the use of compressed air or
``instrument air'' or other gas having little or no VOC would impose a
significant burden on the industry without any added benefit.
Response: The EPA disagrees with the comment that the pneumatic
controller standards must be based on VOC emissions instead of natural
gas bleed rate as a surrogate for VOC emissions rate. Natural gas is
being used as a surrogate for VOC given the proportional relationship
between them. When a natural gas stream is emitted to the atmosphere,
VOC in the gas also reaches the atmosphere since it is a component of
the natural gas stream. The natural gas emissions occur without any
physical separation, chemical separation or chemical reaction process
of the chemical species within the natural gas; therefore, the
proportion of VOC in natural gas is not altered during the course of
being emitted to the atmosphere, and natural gas is an appropriate
surrogate for VOC. As an example, when the natural gas emissions
change, the VOC emissions change proportionately. In addition,
measuring the VOC content of a pneumatic controller's bleed gas adds
cost burden to companies and, to the EPA's knowledge, vendors/
manufacturers do not report the VOC emissions from a pneumatic
controller primarily because the VOC emissions would depend on the gas
composition at the site the pneumatic controller is located.
In the preamble to the proposed rule, the EPA set forth its BSER
analysis for pneumatic controllers. In the TSD, the EPA has provided
cost-effectiveness calculations for the proposed pneumatic device
emission limits. The commenters do not dispute the EPA's analysis.
Rather, the commenters ask that the EPA establish a VOC threshold.
However, the commenters have not provided information on how an
appropriate threshold can be established. One commenter suggests a
threshold of 10-percent VOC content by weight, but has not provided
supporting information justifying this threshold. However, for the
reasons stated in the response to comment in section IX.C.2 of this
preamble, the EPA has decided not to cover in this final rule the
pneumatic controllers in the transmission and storage segment. With
respect to those controllers we are not taking final action at this
time.
Comment: One commenter suggested that the EPA provide a phase-in
period to allow manufacturers and companies time to designate which
controllers qualify as low-bleed. This commenter further notes that
bleed rates are not specified for pneumatic controllers or are
inconsistently represented without distinguishing between the
continuous bleed stream and the actuation stream rates within the gas
consumption specifications.
Response: In the proposed rule, for pneumatic controllers \25\ in
the production segment other than gas processing plants, the EPA
proposed a performance standard of a natural gas bleed rate of 6 scfh
to reflect the use of a low-bleed controller, which we had determined
to be the BSER for reducing VOC emissions from pneumatic controllers in
the production segment.\26\ Owners and operators would demonstrate
compliance based on information in the manufacturers' specifications
for the pneumatic controllers, which we had believed would provide
either the bleed rate or relevant information for such determination.
Upon further investigation, in light of the comments, we conclude that
such information is not always included in current manufacturers'
specifications. We anticipate that manufacturers who currently do not
provide the relevant information for determining bleed rate would
adjust to this need and begin testing their products and provide the
necessary information on the products' specifications. Based on public
comments and other available information, the EPA believes that an
adjustment period is needed, during which owners and operators could
face increased cost and, in some instances, difficulty in obtaining
necessary supplies due to the limited number of currently available
controllers with adequate documentation for determining bleed rate. In
light of the above, we conclude that a low-bleed controller is not the
BSER for pneumatic controller affected facilities in the production
segment (excluding gas processing plants) during this first year. As
explained in the proposed rule, we are not aware of any add-on controls
that are or can be used to reduce VOC emissions from gas driven
pneumatic devices. 76 FR 52760. One commenter broadly suggests that we
consider flares, combustion devices and vapor recovery, but provides no
supporting information. In light of the above, we conclude that there
is no BSER for pneumatic controller affected sources in the production
segment (excluding gas processing plants) during the ``adjustment
period'' mentioned above.
---------------------------------------------------------------------------
\25\ For the reasons explained earlier in this section, we have
changed the definitions of the pneumatic controller affected
facility in the production segment other than gas processing plants
to be a continuous bleed natural gas driven pneumatic controller
with a natural gas bleed rate greater than 6 scfh. This change does
not affect the proposed BSER analysis and VOC limit, which apply to
high-bleed pneumatic controllers in the final rule.
\26\ For reasons explained in section IX.C.2 of this preamble,
unrelated to the comment at issue, the final rule does not include
standards for pneumatic controllers in the transmission and storage
segment.
---------------------------------------------------------------------------
In determining the length of the adjustment period, the EPA
evaluated relevant comments and available information, including
information from promulgation and implementation of 40 CFR part 98,
subpart W of the Greenhouse Gas Reporting rule. Subpart W requires
operators to conduct a complete inventory and report to EPA the number
of low- and high-bleed pneumatic devices, as those terms are defined in
subpart W, over a 3-year period (i.e., \1/3\ of their devices every
year over a 3-year period) starting January 2011. We believe that
efforts are well under way for manufacturers to provide necessary
information to help facilities subject to subpart W determine the
pneumatic controllers' bleed rates and comply with the reporting rule
requirements, \1/3\ of which must be reported by September 2012 and
another third by September 2013 and the entire inventory by September
2014. In light of the above, we do not believe that owners and
operators would face the difficulty described above beyond the first
year after this NSPS becomes effective. After this first year of
``adjustment period,'' we believe owners and operators should have no
problem securing controllers with relevant documentation for
determining bleed rate. Therefore, beginning the second year, the BSER
remains the low-bleed controllers, as proposed.
For the reasons stated above, the final rule contains no standards
for pneumatic controller affected facilities in the production segment
during the first year after this rule becomes effective, but,
thereafter, requires that all new and modified affected facilities to
meet a VOC limit of 6 scfh natural gas bleed rate to reflect the use of
a low-bleed controller. The need for adequate manufacturers'
specifications is not an issue for pneumatic controllers at natural gas
processing plants. For pneumatic controller affected facilities at
natural gas processing plants, we had proposed a zero VOC emission
limit, the compliance of which can be demonstrated by the use of a non-
gas-driven controller system. As noted by commenters, most natural gas
processing plants already use non-gas-driven technology such as
instrument air systems for safety and operational reasons. While one
cannot distinguish
[[Page 49522]]
gas-driven pneumatic controllers of different bleed-rates without
information from manufacturers, a non-gas-driven controller can be
easily identified by visual inspection. Therefore, no change is made
since proposal to the standards for pneumatic controller affected
facilities at gas processing plants.
In response to comments that units already in stock at the time of
proposal cannot be used, the EPA clarifies that pneumatic controllers
that were already in stock or ordered prior to August 23, 2011, are
considered existing sources and, therefore, their installation is not
subject to the pneumatic controllers NSPS in this final rule.
2. Controllers in the Transmission and Storage Segment
Comment: Several commenters requested the EPA reevaluate
requirements for pneumatic controller/devices in the natural gas
transmission segment of the industry. The commenters argue that the
proposed rule's applicability is too broad and would result in an undue
recordkeeping and permitting burden.
Several commenters recommend that 40 CFR part 60, subpart OOOO
should limit pneumatic controller applicability to upstream processes.
Some commenters suggest that, for natural gas transmission and storage,
either pneumatic controllers should be completely excluded or subpart
OOOO should limit applicability to equipment located at
``conventional'' facilities, e.g., within the fence line at a
compressor stations. One commenter recommends limiting the emission
limit requirement to controllers at natural gas processing plants or
locations upstream from gas processing that exceed a defined VOC
threshold. The commenter suggests that this exclusion would reduce
administrative costs in two ways: Mandatory recordkeeping and reporting
would be removed and the documentation required to explain why excluded
controllers would no longer be necessary would be removed. Another
commenter suggests that the EPA state in the final rule that NSPS/
NESHAP applicability alone should not trigger minor source permitting
requirements.
Response: The EPA agrees that cost and other compliance burdens are
important considerations in a rulemaking. In fact, the EPA believes
that such consideration is particularly important here given that
coverage of the transmission sector would result in a significant
number of sources and owner and operators that are not subject to the
current standards. Specifically, were we to finalize standards, we
estimate that we would end up covering an additional 67 sources. We
estimate VOC emissions from these units to be 0.1 tpy per facility or
about 6 tpy nationwide for new sources, which is well below the level
emitted by other affected facilities in this sector.
While our analysis suggests that this is an important set of
sources to regulate, given the large number of sources, and the
relatively low level of VOC emitted from these sources, we have
concluded that additional evaluation of these compliance and burden
issues is appropriate prior to taking final action on pneumatic
controllers in the transmission and storage segment. For this reason,
the requirements for pneumatic controllers in the final rule only apply
to production through processing segments. Our current data indicate
that the VOC content of the natural gas used for pneumatic controllers
in the transmission and storage segment is low, while higher VOC
content natural gas is used in the segments we are regulating. Also,
for the reasons explained in the previous response to comment, no VOC
threshold will be included in this regulation.
3. Cost and Emissions Calculations
Comment: One commenter asserts that the EPA's estimate of 14,000
new and replaced controllers in a given year is grossly underestimated.
By the commenter's data and calculations, approximately 750,000
controllers in Texas alone may need to be replaced (unless an exemption
is granted) once a well becomes subject to the new rule.
Response: The commenter incorrectly claims that the EPA's estimate
of the number of pneumatic controllers installed in a given year is
14,000. In Section 5.3.2 of the TSD, the EPA explains its methodology
for estimating the number of pneumatic controllers in both gas/oil
production and gas transmission and storage. Table 5-3 of the TSD gives
a breakdown of snap-acting versus bleed controllers and shows the total
number of controllers to be 33,673. The commenter did not provide data
to support its claim that there are 750,000 pneumatic controllers in
Texas, or that all of them have bleed rates higher than the proposed
NSPS requirements such that any future replacement would require the
use of a different model (i.e., low bleed or no bleed, depending on its
location) of controller. In any event, the EPA has analyzed and
determined that such replacement is cost-effective. One explanation for
the commenter's high estimate may be a misunderstanding of the
applicability of the final rule. We remind the commenter that the final
rule does not apply to existing sources, unless the existing source is
replaced, modified or reconstructed after August 23, 2011.
D. Major Comments Concerning Compressors
1. Compressors in the Transmission and Storage Segment
Comment: One commenter stated that the agency should exempt
reciprocating and centrifugal compressors in the transmission and
storage sector located after the point of custody transfer, because
there is low-VOC content in natural gas from that sector. Another
commenter urged the EPA to revise 40 CFR 60.5365 to exclude centrifugal
compressors not associated with the Crude Oil and Natural Gas
Production, Transmission, and Distribution sector. One commenter noted
that some large natural gas customers (who are not in the Crude Oil and
Natural Gas Production, Transmission, and Distribution sector) have
natural gas centrifugal compressors that are used to increase the
pressure of natural gas for use in an industrial process, or to
compress natural gas used as the fuel in compressed natural gas
vehicles.
One commenter argued further that even without regard to
fundamental flaws stated in the five factors or methods, there still
would be only trivial and inconsequential VOC reductions relative to
the national VOC inventory. The commenter observed that achieving VOC
reductions of 1 percent of the national anthropogenic VOC inventory
would require over 21,000 regulations at 6.9 tpy, and that the EPA's
estimated annual VOC reductions for compressors was similarly
inconsequential. Nor, said the commenter, had the EPA adequately
considered administrative burdens associated with reporting,
recordkeeping and permitting. The commenter said the trivial,
incremental emissions reductions that would result from the rule failed
to justify the associated compliance costs and that the final rule
should exclude transmission and storage sources. Another commenter
expressly called on the EPA to reanalyze VOC emissions reductions and
to reassess whether the rule would be cost effective. Also taking issue
with supportive data, another commenter said the EPA should suspend
rulemaking and expand its fact-finding to include a statistically
significant sampling of affected sources. One commenter suggested that
the EPA exclude centrifugal compressor facilities that compress natural
gas that is less
[[Page 49523]]
than 10 percent, weight basis, VOC. The commenter stated that
compression of gas that does not contain VOC should not be subject to
standards for VOC. The commenter believes this is consistent with
equipment leak rules which do not regulate components that are not in
VOC service.
Response: The EPA agrees with the commenter that natural gas in the
transmission and storage segment has low-VOC content. The EPA notes
that cost and other compliance burdens are important considerations in
a rulemaking. We estimated the VOC emissions reductions from these
units located in the transmission and storage segment to be 14.1 tpy
for reciprocating compressors and 6.6 tpy for centrifugal compressors,
which is well below the level emitted by other affected facilities in
this segment. The EPA has not fully considered compliance burden for
reciprocating and centrifugal compressors in the transmission and
storage segment and is, therefore, not ready to take final action with
respect to these sources. While our analysis suggests that this is an
important set of sources to regulate, given the number of sources, and
the relatively low level of VOC emitted from these sources, we have
concluded that additional evaluation of these compliance and burden
issues is appropriate prior to taking final action on reciprocating and
centrifugal compressors in the transmission and storage segment.
Also, no VOC threshold will be included in this regulation given
the arbitrary nature of defining one using available data. We believe
this revision also addresses centrifugal compressors not associated
with the Crude Oil and Natural Gas Production, Transmission, and
Distribution sector.
2. Dry Seals Versus Wet Seals
Comment: Several commenters address the issue of whether the EPA
should permit the use of a system other than dry seal to control
emissions from centrifugal compressors. Some commenters provide
information on situations where dry seal systems for centrifugal
compressors are not technically feasible, such as where gas composition
is inadequate, in some processing plants that already have a capture
system in place, and in retrofits of some existing compressors due to
housing design or operational requirements. Commenters opine that the
rule should allow compliance using either system, depending upon
particular circumstances, and should not preclude use of a wet seal-
equipped compressor with controls capable of meeting a 95-percent VOC
control efficiency or routing captured seal-oil gas to a fuel gas,
recycling or other processing system. According to another commenter,
it would not be feasible to capture gas that escapes from a centrifugal
compressor and route it back to a low-pressure fuel stream for
combustion as fuel gas; although such a process would capture a minimal
amount of VOC emissions, the high cost of equipment to recapture the
emissions would make the method described cost-prohibitive.
Commenters generally concurred that a 95-percent reduction in
emissions was achievable through installing a capture system on a wet
seal compressor. In addition, commenters disagreed with the EPA's cost
estimates and concluded that a wet seal capture system is cost
effective.
Response: In the preamble to the proposed rule, the EPA proposed
that a dry seal system is the BSER for centrifugal compressors, but
solicited comments on situations where the use of a dry seal is
infeasible or otherwise inappropriate and wet seal is the only option.
76 FR 52762. As noted above, several commenters provided information on
situations where dry seals are not technically feasible. Therefore, the
EPA has concluded that dry seal is not the BSER for all new and
modified centrifugal compressors. Instead, the EPA separately evaluates
the control options for wet seal compressors. The EPA has identified
one control option through its review of available information,
including comments and other information obtained since proposal. The
option is to route captured seal-oil gas to the compressor suction,
fuel gas system or flare, all of which can achieve 95-percent control
efficiency.
Based on the discrepancy between commenters' and the EPA's cost
data, the EPA re-evaluated its cost information for this control
option. The EPA cost estimates in the proposed rule assumed the use of
a new flare to combust the captured seal oil gas, and, based on
commenter information, the EPA is revising this assumption since a
flare or other combustion source is expected to be available in gas
processing facilities. From reviewing comments received, the EPA is
aware that the captured gas is not always routed to a flare but in many
cases is routed back to the compressor suction or fuel system. Given
this information, the EPA has re-evaluated the costs for the
centrifugal compressor wet seal capture system and determined a system
of this type, in which the seal oil degassing vents are routed to fuel
gas, compressor suction or an existing flare would cost $22,000. The
estimated cost includes an intermediate pressure degassing drum, new
piping, gas demister/filter and a pressure regulator for the fuel line.
With this cost, the estimated VOC control cost effectiveness is $161/
ton of VOC for the processing segment. If savings are included, the
cost effectiveness for VOC control is -$2,408/ton of VOC.
In light of the above, we have determined that the control option
described above is the BSER for wet seal compressors. Accordingly, the
final NSPS would require that wet seal compressors reduce emission by
95 percent. For dry seal compressors, the only emission control option
we have identified is the use of dry seal. Accordingly, there is no
requirement in the final rule for dry seal compressors, and dry seal
compressors are not affected facilities under the NSPS.
3. New Source Definition
Comment: Several commenters oppose the proposal in 40 CFR
60.5365(b) and (c) that a reciprocating compressor be considered as
``commenced construction'' on the date of installation at a facility.
Commenters argue that the EPA was ``arbitrary and capricious'' in
proposing to apply the concept of ``commenced construction'' in the
NSPS context to a relocated compressor, because the agency had no
``reasoned explanation'' for making the change and that applying the
concept of ``commenced construction'' to a relocated compressor is
contrary to the plain language of the CAA.
Response: The EPA traditionally defines the term ``commence
construction,'' as it applies to an equipment, to mean the time an
owner or operator has entered into a contractual obligation to acquire
the equipment. This is reflected in the definition of ``commenced'' in
the General Provisions at 40 CFR 60.2, as well as in the relevant NSPS
(see, e.g., 40 CFR 60.4230(a) of subpart JJJJ). We, therefore, agree
with the commenters that our proposed definition of ``commence
construction'' in 40 CFR 60.5365(b) and 40 CFR 60.5365(c) as the time
of installation is a deviation from our traditional view. Upon
reviewing the comments and re-evaluating the proposed definition, we
conclude that there is no discernible difference between the
compressors at issue and other equipment subject to NSPS that would
make such deviation necessary or appropriate in this case. We have,
therefore, removed these specific definitions of ``commence
construction'' in 40 CFR 60.5365(b) and 40 CFR 60.5365(c) in the final
rule.
[[Page 49524]]
The NSPS also does not apply to relocated compressors. As provided
in the NSPS General Provisions at 40 CFR 60.14(e)(6), relocation of an
existing facility is not modification.
E. Major Comments Concerning Storage Vessels
1. Applicability Threshold Metric
Comment: Numerous commenters objected to the EPA's proposed use of
liquid throughput to determine which storage vessels should be subject
to the standards, asserting that the high variability in volatility of
stored liquids and other parameters affecting emissions makes
throughput a poor indicator of VOC emissions. The commenters indicate
that, as a result, basing applicability on throughput would bring many
storage vessels with low VOC emissions (some less than 1 tpy) under the
standard and the required emission controls would not be cost-
effective. Some commenters point out that certain storage vessels with
high emissions might not be subject to the standards based on
throughput.
Response: In its BSER analysis for storage vessels, the EPA
estimated the VOC emissions for storage vessels with various levels of
throughputs to determine the cost effectiveness of control. In that
analysis, the EPA estimated that storage vessels with throughput rates
of 1 barrel per day (bpd) of condensate or 20 bpd of crude oil are
equivalent to VOC emissions of 6 tpy and determined that control is
cost effective for these storage vessels. The EPA agrees with the
comments that throughput is not a good indicator of VOC emissions and,
therefore, not appropriate for determining the standards'
applicability. However, the EPA has received no comment contesting the
EPA's conclusion that regulating storage vessels emitting 6 tpy or more
of VOC is cost effective and appropriate (the basis of our proposed
throughput limit). Accordingly, in the final rule, the storage vessels
NSPS applies to those emitting 6 tpy or more of VOC. This change from
proposal would ensure that controls will be required only on those
storage vessels where they can be applied cost effectively. This
approach also allows for broader coverage across all types of storage
vessels, regardless of the fluid that is stored or where the storage
vessel may be located. The final rule reflects this change and has
established a VOC emissions threshold of 6 tpy for storage vessels to
require control. Based on our revised cost analysis, we determined that
storage vessels with VOC emissions equal to or greater than 6 tpy or
greater were cost effective to control at $3,400/ton of VOC. The final
rule requires each facility to determine its own emission factor and
calculate the estimated emissions from each storage vessel.
2. Definition of Affected Facility
Comment: Numerous commenters commented on the definition of storage
vessel in 40 CFR part 60, subpart OOOO, calling for greater clarity and
consistency and requesting that certain activities or equipment be
included or excluded from the definition.
Response: The EPA agrees with the commenters who assert that a more
specific and consistent definition of a storage vessel is needed. The
revised definition more clearly focuses on identifying which units are
considered storage vessels under this subpart and which units are not
and describes a storage vessel using terminology similar to that used
in 40 CFR part 63, subpart HH. We believe it is important to be
somewhat consistent in terminology because the NSPS and NESHAP both
apply to the oil and natural production segment where these tanks are
primarily located. We also removed the emissions threshold from the
definition and, instead, based the standard in 40 CFR 60.5395 on the
VOC emission rate of the storage vessel. In response to comments
requesting clarification on whether mobile units are considered storage
vessels, we have set a minimum amount of time (180 consecutive days)
that the storage vessel must be stationed at the same site before it is
subject to 40 CFR part 60, subpart OOOO. Our reasoning for setting this
minimum amount of time is discussed in the response to comment
immediately below. Additionally, we have not excluded wastewater
storage vessels, as the NSPS requires control for all storage vessels
emitting at least 6 tpy of VOC. Further, some wastewater tanks
containing significant amounts of organic compounds could exceed VOC
emissions of 6 tpy. Finally, the revised definition includes specific
exemptions for process vessels and pressure vessels to clarify that
these units are not considered storage vessels. Since the applicability
of subpart OOOO, as finalized, is not based on throughput, we believe
it is not necessary to specify which types of stored materials are
regulated and which are not, as suggested by commenters. If a stored
material is emitting at least 6 tpy of VOC, then the storage vessel
will need to reduce its VOC emissions by 95 percent.
Comment: Some commenters assert that the EPA should limit
applicability to storage vessels that are stationary and should clarify
the meaning of ``stationary'' to include or exclude certain types of
storage vessels.
Additionally, the EPA received comments requesting that the
stationary aspect of the ``storage vessel'' definition should be
consistent with other rules, while acknowledging the particular
scenarios unique to the oil and gas production segment. The commenter
notes that the stationary aspect of a storage vessel is typically
addressed by the EPA in terms of whether it is reasonably portable,
although the EPA sometimes addresses portability based on the size of
the vessel. The commenter states that another criterion specified by
the EPA in several regulations is that ``vessels permanently attached
to motor vehicles'' are not storage vessels, and the EPA has issued a
determination that this exemption extends to storage vessels ``equipped
with a permanently attached wheel assembly and a truck hitch'' (U.S.
Environmental Protection Agency, letter from George T. Czerniak to Ken
Comey, Flint Hills Resources L.P., September 2, 2004). According to the
commenter, this renders most so-called frac tanks, Baker tanks,
International Organization for Standardization tanks, etc., exempt from
the storage vessel provisions when this form of definition is used.
However, the commenter recognizes that such storage vessels sometimes
become effectively ``stationary'' in oil and gas production operations
and suggests that storage vessels should be deemed stationary if they
remain at a given site for more than 180 consecutive days, consistent
with the period of time allowed under 40 CFR 60.14(g) to achieve
compliance after a modification. The commenter notes that this 180-day
period is reasonable given that the definition of non-road engines in
40 CFR 89.2 allows a period of 12 consecutive months.
The commenter also points out that cost effectiveness of the
proposed control measures has been evaluated under the assumption that
storage vessels remain in place for the useful life of the control
equipment, and, thus, the control costs are amortized over a period of
years. Since the cost per ton of emission reductions would be much
higher if the controls were applied to a storage vessel that is only on
site temporarily, the commenter believes that a cost-effectiveness
analysis for permanent storage vessels would not be valid for temporary
storage vessels, and, thus, the control requirements for permanent
storage vessels are not justified for temporary storage vessels. The
commenter provides recommended language for the definition of ``storage
vessel'' that addresses this and other
[[Page 49525]]
concerns. Another commenter similarly states that costly control
requirements are not appropriate for temporary storage vessels (on site
less than 180 days).
Response: Based on the commenter's suggestion, the EPA has revised
the definition of storage vessel to clarify that a storage vessel is
subject to 40 CFR part 60, subpart OOOO if it remains on a given site
for more than 180 consecutive days.
In general, we agree with the commenter's discussion about the
EPA's past practices related to storage vessels. In particular, we
agree that the inherent differences between ``mobile'' or temporary
storage vessels in this source category and other categories indicate
that they should be regulated differently. As mentioned in the previous
response, there are many storage vessels in this source category that
travel from site to site, so we did not feel it was appropriate to
exclude all of these mobile storage vessels from control requirements.
Many temporary storage vessels in this source category are typically
bringing in material such as fracking fluid to well sites and can stay
at a well site for up to several months in order to receive flowback.
These storage vessels are considered to be an essential part of the
drilling and production operation, more akin to how permanent storage
vessels are utilized in the refining and organic chemical manufacturing
sectors, rather than to conventional tank trucks that are typically
excluded in other EPA rules. Therefore, we believe that 180 days is an
appropriate period of time to establish a temporary tank as being
subject to 40 CFR part 60, subpart OOOO, and, therefore, potentially
required to install controls.
3. References to MACT Standards
Comment: The EPA received comment asserting that the outcome of its
best demonstrated technology (BDT) analysis for proposed 40 CFR part
60, subpart OOOO was calculated to achieve the same level of control as
40 CFR part 63, subpart HH--undermining the BDT determination and
effectively (and unlawfully) extending subpart HH major source MACT
requirements to area source storage vessels.
As a result, the commenter asserts that the EPA's analysis
precludes other potentially relevant regulatory alternatives--such as
marginally less effective controls that might be applied to a broader
range of storage vessels. The commenter states that the EPA's failure
to consider other control techniques and other levels of control
efficiency that might be achieved by its preferred techniques is
arbitrary and capricious.
Response: The commenter incorrectly asserts that the EPA's NSPS for
storage vessels was designed to achieve the same level of control as
MACT in 40 CFR part 63, subpart HH. In Portland Cement Assoc. v. EPA,
665 F.3d 177 (D.C. Cir. 2011), the United States Court of Appeals for
the District of Columbia Circuit rejected an argument that the EPA
adopted NESHAP PM standards for NSPS, noting that the EPA arrived at
the same limit for both NESHAP and NSPS using two different mechanisms.
Similarly, in this case, although both the NESHAP and the NSPS require
95-percent control, the EPA established the two standards based on
separate mechanisms. The EPA established the MACT standard in 1998
pursuant to section 112(d)(2) and (3) of the CAA. In contrast, the EPA
established the NSPS based on BSER analysis under CAA section 111. The
BSER analysis for storage vessels consists of the same steps as those
for other affected sources evaluated in the proposed NSPS.
Specifically, the EPA evaluated available information to identify VOC
control options. The EPA then assessed various aspects of the control
options, including their VOC reduction potentials, their cost
effectiveness and secondary air impacts. The commenter did not claim
that any part of the EPA's BSER analysis above was inaccurate or
inappropriate. For the reasons stated above, the commenter's assertion
is without support.
The commenter also claims that the EPA only analyzed two controls
and, therefore, failed to consider other ``potentially relevant
regulatory alternatives.'' However, the commenter did not identify any
other control option for the EPA's consideration. The commenter simply
suggests that the EPA should consider some less effective controls,
which the commenter claims would have led to greater coverage. Without
more information, it is unclear whether a less effective control than
that we have identified would, in fact, qualify as BSER for controlling
VOC emissions from storage vessels or would have resulted in coverage
of additional storage vessels.
Comment: Two commenters state that the cost of the performance
tests, monitoring, recordkeeping, etc., that are required through
cross-references to 40 CFR part 63, subpart HH were not adequately
considered by the EPA in the cost-effectiveness determination for 40
CFR part 60, subpart OOOO, which applies to dispersed locations that do
not have electricity or automation, and have limited remote
transmitting unit space.
Response: The EPA does not take into account monitoring,
recordkeeping and reporting costs in determining cost effectiveness of
controls and in evaluating BSER. Based on this and other comments
detailed in the response to comments for this final rulemaking, the EPA
removed from 40 CFR part 60, subpart OOOO the citations to the
requirements for performance tests, monitoring, recordkeeping, etc., in
40 CFR part 63, subpart HH and incorporated these subpart HH
requirements into subpart OOOO. During the incorporation process, we
made minor revisions to the subpart HH requirements, as appropriate for
subpart OOOO. For example, we removed references to glycol dehydrators
and paragraphs listed as ``reserved.''
4. Availability of Control Equipment
Comment: Some commenters believe that there will be a shortage of
control equipment available to meet the proposed storage vessel
requirements, and recommend revisions to the compliance deadline for
storage vessels based on a variety of considerations, including the
availability of control devices, lead time needed for manufacturer
testing of their combustors to be compliant with the NSPS and time
needed to install the compliant devices.
Response: We agree that it will likely take some time beyond the
promulgation date of the NSPS for combustor manufacturers to have
control devices constructed, tested, documented and available for
operators to install in efforts to comply with the storage vessel
requirements of the NSPS. Under the final rule, operators are not
required to conduct individual performance tests on combustors
installed in the field if the combustor manufacturer tests and
documents for the owner or operator that the model achieves a control
efficiency of 95.0 percent. The time required for testing and
documentation is often longer than for a single model when
manufacturers provide multiple models for varying applications based on
capacity. We believe this testing and documentation program would
require an ``adjustment period'' for manufacturers to be ready to
supply the operators with the correct equipment they need.
We considered whether it would be feasible for on-site testing to
mitigate the shortage of manufacturer tested combustors. Although
owners and operators can test their individual combustors in the field
to determine combustor efficiency, such emissions testing is expensive
and can only be
[[Page 49526]]
performed if testing consultants are available to conduct the testing.
We believe that immediately after the effective date of the NSPS there
will be a shortage of available testing consultants concurrent with the
shortage of pre-tested combustor models. As a result, we conclude that
on-site testing would not sufficiently mitigate the difficulty of
owners and operators complying with the NSPS.
We evaluated whether controls other than combustors would be
available during this adjustment period. Although vapor recovery units
(VRU) can provide 95.0-percent control for storage vessels and are one
means of meeting the storage vessel standards in the NSPS, VRU cannot
be used in every situation. For example, storage vessels located
remotely where there is no available electrical service may not be able
to be controlled using VRU. In addition, storage vessels with low
concentration emission streams or fluctuating emissions may not be
amenable to control by VRU. Further, VRU installations would also
require on-site testing, and owners and operators would be hampered by
the same consultant shortage situation described above for combustors.
In light of the above, we conclude that there is no BSER for
storage vessel affected sources during the first year after
promulgation, which we believe is appropriate for the adjustment period
mentioned above. At the end of this adjustment period, we believe
owners and operators should have no problem securing control devices
that are manufacturer-tested and have appropriate documentation for
determining control efficiency. Accordingly, the final rule provides
for a 1-year phase-in beginning October 15, 2012 before the 95.0-
percent control requirement is effective.
With regard to providing time for operators to establish the need
for controls and install them where called for, the EPA agrees that
some lag time may be needed after initial start-up for the owner or
operator to determine the long-term production level of a well and to
procure the appropriate control equipment. The EPA evaluated the
approach taken in the Wyoming rules for new sources, which allows from
30 to 90 days for a source to achieve compliance, depending on the area
of the state. Wyoming allows only 30 days in ozone nonattainment areas,
60 days for concentrated development areas or 90 days elsewhere in the
state. The EPA believes that 60 days is a reasonable period for
controlling new storage vessels at wells sites with no wells already in
production.
However, for replacement storage vessels or additional storage
vessels at well sites with one or more wells already in production, we
believe the operator already should have information on liquid
composition and throughput. This information would allow estimation of
VOC emissions to determine applicability of control requirements and
for acquisition and installation of a control device concurrent with
the replacement or additional storage vessel being installed. In the
final rule, for storage vessels constructed, modified or reconstructed
at well sites with no well already in production, we have provided for
a 30-day period for throughput to stabilize and for the operator to
estimate VOC emissions to determine whether a control device will be
required. If VOC emissions are estimated to be at least 6 tpy, the
operator is provided an additional 30 days for the control device to
become operational. We believe that the Wyoming experience illustrates
that this will be sufficient time to size and obtain suitable controls.
F. Major Comments Concerning Notification, Recordkeeping and Reporting
Requirements
1. 30-Day Notification and Annual Reports
Comment: Multiple commenters state that the 30-day advance
notification of well completions under 40 CFR 60.5420(a) should be
removed from the final rule. Commenters assert that this and
notification requirements in 40 CFR 60.7(a) are unduly burdensome and
costly, not adequately explained, not related to verifying compliance
with the proposed rule and could conflict with the need to protect
proprietary business information.
Multiple commenters also note that industry's estimate of annual
completions is several times higher than the EPA's estimate of 20,000
completions following fracturing and completions following refracturing
annually. The commenters believe that these requirements will likely
overwhelm both regulated entities and state regulators alike.
Commenters offer suggestions, including requiring annual certifications
or maintaining records available for inspection, reducing the proposed
advance notification requirement to 5-10 days and considering
notification programs such as those in Texas and Wyoming. Different
commenters support or oppose requiring a 30-day advance notice with
follow-up notification of 1-2 days before an impending completion.
Several commenters suggest that the EPA should coordinate with
state and local agencies to eliminate duplicative recordkeeping and
reporting requirements, and that records of interest other than those
submitted to the respective Oil and Gas Commissions should only be
required to be retained and available upon inspection, similar to other
permit requirements.
Several commenters do not agree that an annual report under 40 CFR
60.7(a)(1), 40 CFR 60.7(a)(3) and 40 CFR 60.7(a)(4) adds any value for
verifying compliance and the EPA should remove this requirement from
the final rule. The commenters add that the best method for compliance
is for an owner or operator to maintain necessary records and to have
the records available for review during an on-site inspection. One
commenter suggests the annual report should include for each type of
affected facility (1) the total number of affected facilities at the
site; (2) the number of facilities that became affected facilities
during the reporting period; (3) the number of exempted facilities; and
(4) the number of affected facilities with a non-compliance situation
during the reporting period. One commenter suggests that it would be
easier for facilities to submit an annual report on a set date each
year, and multiple affected facilities could be included in a single
report. Two commenters propose that all notifications for each year be
delivered in a single annual report corresponding to the reporting
period in which the affected facilities become subject to the rule. One
commenter suggests that operators should be required to keep records at
the nearest manned office, but reports should only be required if they
are requested by the EPA.
The commenters recommend, where feasible, streamlining the final
notification and reporting requirements to eliminate unduly burdensome
notification and reporting requirements.
Response: The EPA agrees that certain notification, recordkeeping
and reporting requirements in the General Provisions are unduly
burdensome for the new affected facilities in this NSPS. For that
reason, well completions, pneumatic controllers and storage vessels
will be exempt from the notifications required by 40 CFR 60.7(a)(1),
(3) and (4). We agree that notifications of well completions should be
as streamlined as possible to remove excess burden from both the owners
and operators and regulatory agencies, as well. As a result, we have
removed the 30-day advance notification requirement and instead are
requiring an advance notice via email to the EPA or delegated
[[Page 49527]]
authority no later than 2 days prior to completion.
To avoid duplicative and potentially conflicting notification
requirements and to relieve notification burden from owners and
operators, we have added a provision in the final rule that, if an
owner or operator has met the state requirements for advance
notification of well completions, then the owner and operator are
considered to have met the advance notification requirement for gas
well completions under the NSPS.
We also believe that the operator should be provided flexibility to
use new technology to document compliance that would result in less
paperwork burden on the part of the operators themselves and on
regulators. To lessen the reporting burden, the final recordkeeping and
reporting requirements for well completions also provide for a
streamlining option that owners and operators may choose in lieu of the
standard annual reporting requirements. The standard annual report must
include copies of all well completion records for each gas well
affected facility for which a completion operation was performed during
the reporting period. The alternative, streamlined annual report for
gas well affected facilities requires submission of a list, with
identifying information of all affected gas wells completed, electronic
or hard copy photographs documenting REC in progress for each well for
which REC was required and the self-certification required in the
standard annual report. The operator retains a digital image of each
REC in progress. The image must include a digital date stamp and
geographic coordinates stamp to help link the photograph with the
specific well completion operation. Operators are not required to take
advantage of the optional recordkeeping and reporting approach, as some
may choose to follow the standard reporting requirements. Under either
approach, the report must include a record of all deviations during the
reporting period in cases where well completion operations with
hydraulic fracturing were not performed in compliance with the
requirements for each gas well affected facility.
Comment: One commenter requested that the EPA add a self-
certification requirement to the annual report similar to that used in
the title V program. The commenter recommended that the final rule
require the annual report to include a statement signed by a senior
official of the facility attesting to the truth, accuracy and
completeness of the report.
The commenter also requested that the EPA require that the annual
reports be submitted electronically to facilitate making the reports
publicly available. The commenter suggested using social media outlets,
smart phone applications and other electronic means to make the annual
reports readily available.
Response: The EPA agrees that self-certification is an important
mechanism for assuring the public that the information submitted by
each facility is accurate. In addition, the title V program has
successfully employed self-certification since its inception.
Therefore, we are requiring self-certification, based on requirements
in the title V program, in the final rule.
While we agree that having annual reports readily available to the
public is a desirable goal, we did not identify any reporting programs
or electronic databases that may be used for this purpose without
significant modification. Therefore, we are not requiring annual
reports to be submitted electronically, but we will continue to
evaluate this option in the future.
2. Duplicative Recordkeeping and Reporting Requirements
Comment: Multiple commenters state that the notification,
recordkeeping, monitoring and annual reporting requirements in the
proposed NSPS are duplicative and extremely burdensome for operators
and for state regulators with limited resources. The commenters make
both general and specific recommendations to revise the reporting
requirements in the final rule to eliminate duplication and reduce
burden or better inform the public and regulatory agencies about
deviations. Some commenters would eliminate all or some reports, while
others argue that reporting is an essential compliance and enforcement
mechanism and that additional information should be provided. Some
commenters feel that an owner or operator should maintain necessary
records and have them available for review.
Commenters want the compliance assurance requirements to be
appropriate for the oil and gas industry and commensurate to the
environmental benefit that will be generated. For example, some
commenters feel that the EPA should exempt small sources regulated
under this rule from the notification and reporting requirements.
Response: We have considered these and other related comments
presented in the response to comments regarding the proposed reporting
requirements. The EPA agrees that certain notification, recordkeeping
and reporting requirements are unduly burdensome and believes it is
important to minimize the burden of reporting requirements. However, as
noted in several comments, states and other enforcement entities are
confronting limited resources and visiting sites is not always
practical and is particularly challenging in this industry. For that
reason, the EPA believes notifications and reporting requirements are
vital to ensure compliance with our regulations. Therefore, the EPA has
evaluated the proposed notification, recordkeeping and reporting
requirements in an effort to streamline the requirements to reduce
burden on both industry and enforcement at the same time, assuring
compliance with the NSPS. In the final rule, the EPA has removed or
otherwise revised proposed reporting requirements that the EPA believes
to be duplicative or unnecessary, including, but not limited to, those
raised in the comments. These changes will streamline the reporting
process and reduce the reporting burden on sources, including small
sources. For example, as previously discussed, well completions and
continuous bleed natural gas controllers are exempt from the
notifications required by 40 CFR 60.7(a)(1), 40 CFR 60.7(a)(3) and 40
CFR 60.7(a)(4). In addition, the EPA has revised the rule language such
that only continuous bleed natural gas controllers installed, modified
or replaced during the reporting period are reported in the annual
report. In addition, the EPA has revised the 30-day individual
notification requirement for well completions, as discussed above.
3. Electronic Reporting of Emissions Data
Comment: Commenters suggest a variety of ways in which electronic
reporting could be structured and implemented, with attention to
coordination with various CAA requirements and programs to avoid
duplicative and potentially burdensome requirements. Several commenters
support electronic reporting of emissions data from all sources to be
stored on existing EPA databases, such as the Electronic Greenhouse Gas
Reporting Tool (e-GGRT) or added to the Toxics Release Inventory, and
available to the public. These commenters believe that communities must
have access to air quality information in order to protect public
health. One commenter objects to the use of e-GGRT as a reporting
mechanism in place of a state's own tracking system, where the state
has enforcement responsibility for the emissions date and tracking of
sources subject to the proposed rule. The commenters also suggested a
variety of ways in which electronic
[[Page 49528]]
reporting could be structured and implemented.
Several commenters oppose the implementation of electronic
reporting at this time and are concerned that an ERT will result in
numerous complications and undue additional burden. The commenters
point out that the EPA's experience with e-GGRT indicates that
considerable time and resources are needed to develop and implement
efficient systems and to ensure that electronic reporting enhances
efficiency rather than incurring additional burden on affected sources.
The commenters state that a potential disadvantage associated with an
ERT is that new and/or alternative test methods would not be in the
system. In addition, the commenters believe that an ERT could be
complicated and burdensome for smaller companies that lack
environmental personnel or experience with electronic reporting under
other rules. The commenters suggest that if the EPA delegates authority
to states to implement and enforce the standards, some states may be
unable or unwilling to accept electronic reports. The commenters urge
the EPA to consider other more simplified options to report only the
needed information.
Response: While the EPA supports and encourages electronic
reporting, after further consideration of all the comments, we do not
believe the e-GGRT is the appropriate mechanism for electronic
reporting under this rule, as recommended by some commenters. The e-
GGRT is not designed to accept all of the types of information required
to be reported under the final rule, and significant modification of
the system would be required to make it operational for this rule.
However, the final rule does include reporting of performance test
data via the ERT. The EPA must have performance test data to conduct
effective reviews of CAA sections 112 and 129 standards, as well as for
many other purposes, including compliance determinations, emission
factor development and annual emission rate determinations. In
conducting these required reviews, the EPA has found it ineffective and
time consuming, not only for us, but also for regulatory agencies and
source owners and operators, 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.
In the final rule, as a step to increase the ease and efficiency of
data submittal and improve data accessibility, the EPA is requiring the
electronic submittal of select performance test data. Data entry will
be through an electronic emissions test report structure called the
ERT. The ERT will generate an electronic report which will be submitted
using the CEDRI. The submitted report is submitted through the EPA's
CDX network for storage in the WebFIRE database making submittal of
data very straightforward and easy. Webfire is the EPA's online
emissions factor repository, retrieval and development tool. The
WebFIRE database is open to the public and contains the EPA's
recommended emissions factors for criteria and HAP for industrial and
non-industrial processes. Emissions data collected from the oil and
natural gas sector, as well as many other sectors, will be used to
update our emissions factors. The data will also be used by the EPA's
rule writers to make better informed decisions and learn more detailed
information about emissions from sources. The electronic reporting
requirement in this rule (and other NSPS/NESHAP rules) is only for test
methods that are supported by the ERT.
One major advantage of submitting 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 what testing information 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.
State, local and tribal agencies can also benefit from a more
streamlined and accurate review of electronic data submitted to them.
The ERT allows for an electronic review process rather than a manual
data assessment making review and evaluation of the data and
calculations easier and more efficient. Finally, another benefit of
submitting data to WebFIRE electronically is that these data will
greatly improve the overall quality of the existing and new emission
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 will be able to ensure that emission
factors, when updated, represent the most current range of operational
practices.
X. Summary of Significant NESHAP Comments and Responses
For purposes of this document, the text within the comment
summaries was provided by the commenter(s) and represents their
opinion(s), regardless of whether the summary specifically indicates
that the statement is from a commenter(s) (e.g., ``The commenter
states'' or ``The commenters assert''). The comment summaries do not
represent the EPA's opinion unless the response to the comment
specifically agrees with all or a portion of the comment.
A. Major Comments Concerning Previously Unregulated Sources
Comment: One commenter asserts that, although the EPA's original
MACT analysis covered all storage vessels, it issued a MACT standard at
that time that applied to storage vessels with the PFE only. The
commenter states that, while they support the EPA's effort to correct
this omission, the initial analysis for the tanks that the agency did
regulate in 1999 was seriously flawed, and the proposed rule provides
no justification for continuing to rely on a 13-year old analysis to
propose a MACT standard for an entirely new universe of storage vessel
sources. Thus, according to the commenter, the EPA's failure to
properly calculate the MACT floor in setting the MACT standard for
storage vessels violates CAA section 112(d)(2) and (3).
The commenter states that, because this method has been found to be
unlawful and substantially more data are available at this time, the
EPA must now recalculate the MACT floor and MACT limits for tanks with
the PFE. Cement Kiln Recycling Coalition, et. al. v. U.S. EPA, 255 F.3d
855, 863-64 (D.C. Cir. 2001). The commenter asserts that, in addition
and partly as a consequence of its unlawful reliance on the prior
standards, the EPA also has failed to fulfill the beyond-the-floor
requirement of CAA section 112(d)(2). The commenter opines that, absent
an up-to-date analysis based on current emission controls, an
appropriate beyond-the-floor determination cannot be made.
Two commenters do not believe that the dataset used is
representative of currently operating small glycol dehydrators. One
commenter believes that the EPA has not satisfied section 112(d)(2) and
(3) of the CAA and that the EPA needs to calculate the MACT
[[Page 49529]]
limit based on the best-performing sources that currently exist.
One commenter recommends that the EPA base its MACT floor analyses
on emissions data from a representative population of small dehydrators
that characterize the population of affected sources within the
category or subcategory. The commenter reports that more current data
sources may be available, such as dehydrator emissions data reported to
state agencies in annual emission reports or in permit applications.
One commenter opines that the EPA's proposal misses the opportunity
and fails to fulfill the agency's responsibility to properly calculate
the MACT for all sources in this sector based on current, reliable and
representative emission test data. The commenter believes that, by
relying on an incomplete and outdated dataset to set MACT floors and
limits, the EPA has ignored data demonstrating trends in practices,
processes and technologies and the resulting improved performance that
CAA section 112(d) mandates. The commenter asserts that the EPA ignores
the potential HAP emissions that the control devices themselves emit by
failing to collect such emissions data from facilities that have
installed control devices. The commenter argues that the EPA must
collect the appropriate emission test data needed in order to
recalculate and set a proper MACT for glycol dehydrators, storage
vessels and equipment leaks.
One commenter states that section 112 of the CAA requires the EPA
to set a NESHAP for each category or subcategory of ``major sources''
of HAP emissions. 42 U.S.C. 7412(d)(1). The commenter asserts that the
EPA must set CAA section 112(d) emission standards based on ``maximum
achievable control technology'' or ``MACT.'' The commenter states that
the EPA largely bases its MACT proposal for small glycol dehydrators on
emissions data collected from the industry during the development of
the original MACT standards. 76 FR 52768. The commenter contends that
the data were collected prior to 1997 and did not adequately represent
the emissions profile at that time, and do not reflect the significant
changes in the industry and other technological developments that have
occurred during the past 13 years. According to the commenter, the EPA
has not provided a reasoned explanation of how those data could be
representative of currently operating glycol dehydrators and associated
emission reductions, and how proposals based on those data can
currently meet the MACT requirements for new and existing sources. The
commenter states that the dehydrator technology performance in 1997 was
not accurately reflected in the legacy EPA dataset and has advanced
significantly in the past 13 years. Consequently, according to the
commenter, the EPA has not provided a reasoned explanation of how those
data could be representative of currently operating glycol dehydrators
and associated emission reductions, and how proposals based on those
data can currently meet the MACT requirements for new and existing
sources. The commenter believes this is critical because the 2005 NEI
data reveal that improvements in the environmental performance of the
category have progressed such that there are far more units in service
with lower emissions than reflected in the 1997 data.
One commenter states that the EPA did not collect recent data
regarding emissions of HAP, including BTEX, from small glycol
dehydrators in either source sector in support of this rulemaking.
Instead, according to the commenter, the EPA appears to have relied on
data collected in the prior MACT rulemaking, going back to 1998 or
prior. The commenter believes that the EPA's analysis is flawed and
questionable because it simply relies on the best-performing sources
that existed a decade ago and fails to identify the best controlled
sources today. The commenter contends that it is unlikely that these
MACT standards reflect either the current best controlled similar
source emissions or the average of the top 12 percent of the currently
best controlled sources. The commenter states that, while the EPA
appropriately proposes to set a MACT limit for these sources for the
first time, the EPA's use of out-dated data fails to demonstrate that
its proposed limit is stringent enough in light of significant
developments in emission control technologies and practices that have
occurred since 1998.
Response: One commenter argues that EPA has not satisfied sections
112(d)(2) and (3) of the CAA, because the MACT standards set in the
1999 rule have not been re-calculated using current data. To the extent
the commenter is arguing that CAA section 112(d)(6) requires that the
EPA recalculate the MACT standards set in 1999, based on current
emissions test data, the commenter is incorrect. In NRDC v. EPA, 529
F.3d 1077, 1084 (D.C. Cir. 2008), the District of Columbia Circuit held
that it ``[did] not think the words `review, and revise as necessary'
can be construed reasonably as imposing any such obligation'' to re-
calculate the MACT floors. NRDC v. EPA, 529 F.3d 1077, 1084 (D.C. Cir.
2008).
Moreover, in this action, we did not re-open the MACT standards in
40 CFR part 63, subpart HH for large glycol dehydrators, storage
vessels with the PFE and equipment leaks for or in 40 CFR part 63,
subpart HHH for large glycol dehydrators. As such, the commenter's
request that we re-calculate those standards based on current emissions
data is outside the scope of this rulemaking. We did, however, conduct
a CAA section 112(d)(6) technology review for subpart HH and determined
that there have been no developments in practices, processes or control
technologies for large glycol dehydrators, storage vessels with the PFE
and equipment leaks and that there have been developments for equipment
leaks. See Technology Review for the Final Amendments to Standards for
the Oil and Natural Gas Production and Natural Gas Transmission and
Storage Source Categories and responses on section 112(d)(6) comments
below. We also conducted a CAA section 112(d)(6) technology review for
subpart HHH and determined that there have been no developments in
practices, processes or control technologies for large glycol
dehydrators. Id.
The remaining comments focus on the data the agency used to set the
proposed MACT standards for small glycol dehydrators, which were left
unregulated in the 1999 rule. The commenters claim that the data the
EPA used to set the BTEX MACT standards for the small glycol
dehydrators subcategory are outdated and that the EPA must collect new
data. However, CAA section 112(d)(3) specifically provides that the
Agency is to determine the average emission limit achieved by the best
performing 12 percent of existing sources ``(for which the
Administrator has emissions information).'' Thus, the EPA is not
required to collect information if it determines that the information
it has is sufficient for it to calculate the MACT standards consistent
with the requirements of CAA section 112. Although the available
emissions information is over a decade old, the available controls for
reducing BTEX emissions from small glycol dehydrators and their control
efficiencies have remained the same during this period, and the
commenters have not provided any data to the contrary.\27\ We,
[[Page 49530]]
therefore, believe the data we have are still representative of the
performance of the small dehydrators.
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\27\ Memorandum from Brown, Heather, EC/R Inc., to Moore, Bruce,
U.S. EPA, titled Technology Review for the Final Amendments to
Standards for the Oil and Natural Gas Production and Natural Gas
Transmission and Storage Source Categories. Dated April 17, 2012.
---------------------------------------------------------------------------
Moreover, we believe that the collection and analysis of additional
data would take time and further delay control of these sources, which
we do not think is warranted where, as here, we believe the data on
BTEX emissions for the subcategory of small glycol dehydrators are
still representative of these sources' performance today and the
commenter did not provide any data that indicates otherwise.
Finally, for small glycol dehydrators, we considered using more
current available data, like the 2005 NEI, however, the NEI dataset
lacks specific information that we believe is relevant to identifying
the best performing units. Specifically, the NEI data lacks information
on inlet HAP content and gas throughput, both of which affect a glycol
dehydrator's HAP emissions. Inlet HAP content varies from well site to
well site. A well-controlled glycol dehydrator at a well site with high
inlet HAP content may have higher HAP emissions than a totally
uncontrolled glycol dehydrator at a well site with a low inlet HAP
content. Natural gas throughput also affects a glycol dehydrator's
overall emissions (i.e., low throughput units will tend to have lower
overall emissions, and vice versa). For the reasons stated above, in
addition to emissions, we need to consider the inlet HAP content and
gas throughput of the small glycol dehydrators in order to properly
identify the best performing sources and establish the MACT standard
for this subcategory. However, information on natural gas throughput
and inlet HAP content is not included in the NEI or any other readily
available data source. Therefore, we used the 1997 data which included
such information for the small dehydrators.
Comment: One commenter supports the EPA's regulation of previously
unregulated sources in the oil and natural gas sector and the commenter
asserts that CAA sections 112(c) and 112(k) (Urban Air Toxics Strategy)
support their position regarding the regulation of previously
unregulated sources. The commenter asserts that historical regulation
of emission sources within the sector leaves a large number of
dehydrators, storage vessels and equipment at gas processing plants
unregulated. Additionally, the commenter states that historical
regulation has also not limited emissions from a number of other
emission sources (i.e., wells, pneumatic devices, compressor seals,
valves, or flanges or other production equipment located at oil and gas
production facilities or natural gas storage transmission facilities).
One commenter supports the EPA's recognition of the need to control
emissions from previously uncontrolled emission points and commends the
EPA on addressing small glycol dehydration units and storage vessels
without the PFE. The commenters request that the EPA address all of the
uncontrolled HAP emission points of which it is aware.
Response: This rule establishes MACT standards for major sources of
small glycol dehydrators that were left unregulated in the 1999 MACT
rule. As explained further below, in several recent rulemakings, we
have chosen to fix certain underlying defects in existing MACT
standards under CAA sections 112(d)(2) and (3), which are the
provisions that directly govern the initial promulgation of MACT
standards (see National Emission Standards for Hazardous Air Pollutants
From Petroleum Refineries, October 28, 2009, 74 FR 55670; and National
Emission Standards for Hazardous Air Pollutants: Group I Polymers and
Resins; Marine Tank Vessel Loading Operations; Pharmaceuticals
Production; and the Printing and Publishing Industry, April 21, 2011,
76 FR 22566). We believe that this approach is reasonable because using
those provisions ensures that the process and considerations are those
associated with initially establishing a MACT standard, and it is
reasonable to make corrections following the process that would have
been followed if we had not made an error at the time of the original
promulgation. We appreciate the commenter's support for regulating
small glycol dehydrators.
Although the agency had proposed MACT standards under CAA sections
112(d)(2) and (3) for the subcategory of storage vessels without the
PFE, we are not finalizing those standards here. Based on our review of
the comments, we believe that we need additional data in order to set
an emission standard for these vessels. We intend to collect the
appropriate data and propose a MACT emission standard under CAA
sections 112(d)(2) and (3) of the CAA.
The commenter identifies certain emission sources, other than small
glycol dehydrators and storage vessels without the PFE (e.g., wells),
that it alleges are uncontrolled. CAA section 112(n)(4)(A) prohibits
aggregation of emissions from any oil and gas exploration or production
wells (with their associated equipment) in determining major source
status or for any purpose under CAA section 112. In light of this
prohibition on aggregation, and the fact that the sources identified by
the commenter likely would not, if viewed alone, qualify as a major
source, it is not clear whether emissions from the sources identified
by the commenter can be addressed by a major source NESHAP.\28\
---------------------------------------------------------------------------
\28\ Even if the commenter were to identify an unregulated
emission point under the NESHAP, it can always petition the agency
to revise the 1999 MACT standards.
---------------------------------------------------------------------------
The commenter also references CAA section 112(k) (and the Urban Air
Toxic Strategy). CAA section 112(k) is designed to address area source
emissions in urban areas. This rule involves a review of 40 CFR part
63, subparts HH and HHH, both of which address major sources, not area
sources. Further, oil and gas production facilities are typically not
sited in urban areas.
To the extent that the commenter is requesting EPA to list area
source oil and gas production wells, such a request is outside the
scope of this action. See CAA section 112(n)(4)(B) (specifying certain
requirements for listing ``oil and gas production wells (with its
associated equipment)'' as an area source category).
B. Major Comments Concerning the Risk Review
Comment: One commenter states that the EPA's analysis for 40 CFR
part 63, subpart HH revealed two facilities (Hawkins Gas Plant,
Hawkins, Texas, and Kathleen Tharp 2, Huffman, Texas) with a cancer MIR
greater than 100-in-1 million based on MACT allowable emissions. The
commenter notes that since the EPA determined that these facilities had
a cancer MIR greater than 100-in-1 million based on MACT allowable
emissions, the EPA determined that the risks are unacceptable for the
Oil and Natural Gas Production MACT source category and additional
regulation was needed. However, the commenter believes these results
are entirely incorrect due to fundamental errors in the EPA's
calculations of MACT allowable risk for these two facilities. In
addition, even if the analysis had been correct, the commenter states
there are significant issues associated with the data for both of these
facilities, which the commenter discusses in detail, that the commenter
believes are sufficient to invalidate the results and the EPA's
conclusion that risks from the Oil and Natural Gas Production source
category are unacceptable.
Response: We have reviewed our risk results for the Oil and Natural
Gas Production source category and agree
[[Page 49531]]
with the commenter that a number of errors were made in our analysis,
including those noted by the commenter. As explained in VII.A.2 of this
preamble, we have revised the risk assessment for this major source
category to correct certain mistakes made in the analysis supporting
the proposed rule.
Based on our revised risk assessment, in which we evaluated the
risks that remain after promulgation of the original MACT standards, as
well as the MACT standards for small glycol dehydrators established in
this final rule, we have determined the risks for the Oil and Natural
Gas Production major source category are acceptable and that the MACT
standards (including those promulgated here for small glycol
dehydrators) provide an ample margin of safety. Further, we are
retaining the 0.9 Mg/yr benzene compliance alternative, which we had
proposed to remove based on our incorrect conclusion that this
alternative was driving the risk for this major source category.
Comment: One commenter states that the EPA bases the decision to
eliminate the 0.9 Mg/yr benzene emission limitation for 40 CFR part 63,
subpart HHH on two basic factors: (1) It would reduce the cancer MIR
from 90-in-1 million to 20-in-1 million, and (2) the cost effectiveness
to comply with this option is reasonable. The commenter states that
both of these conclusions are erroneous.
First, the commenter states that removal of 0.9 Mg/yr benzene
alternative does not reduce risk. The commenter states that the EPA's
own technical analysis indicates that removal of the 0.9 Mg/yr benzene
alternative would have no effect on the MIR.
Secondly, the commenter states that the EPA's cost analysis is
severely flawed. The commenter also states that the EPA noted at
proposal, that the cost-effectiveness associated with removing the 0.9
Mg/yr benzene compliance alternative for natural gas transmission and
storage facilities was reasonable. However, the commenter explained
that the cost estimates used by the EPA in the ample margin of safety
determination are inadequate. According to the commenter, the EPA did
not conduct any analysis using actual data. Rather, the commenter notes
that the EPA used costs estimated for small dehydrators and made
general assumptions to estimate an upper-end cost effectiveness for
removing the 0.9 Mg/yr benzene alternative limit for large dehydrators
at natural gas transmission and storage facilities. The commenter
believes that, in general, the emission reductions for dehydrators
forced to switch from the 0.9 Mg/yr benzene alternative to 95-percent
control would be considerably less than those achieved by small
dehydrators. The commenter further notes that the cost-effectiveness
calculated for small dehydrators is based on a 95-percent reduction
from an uncontrolled baseline level. According to the commenter, if a
large dehydrator has installed controls to meet the 0.9 Mg/yr
alternative benzene limitation, the cost effectiveness must be based on
the incremental reduction between the existing controls and 95 percent.
The commenter states that the EPA has provided no evidence that these
incremental reductions would be greater than or equal to the 95-percent
reductions that would be achieved for smaller dehydrators. In
conclusion, the commenter states that the rationale used by the EPA in
the preamble to support the removal of the 0.9 Mg/yr compliance
alternative for dehydrators at natural gas transmission and storage
facilities under section 112(f)(2) of the CAA is not supported by any
of the background technical documentation and analyses. The commenter
believes that the EPA has no basis under any other CAA authority for
this action.
Response: In response to comments, we re-examined our risk
assessment for the Natural Gas Transmission and Storage source category
and discovered a number of errors, which we have discussed in more
detail in section VII.B.2 of this preamble. As explained in that
section, we have revised the risk assessment for this major source
category to correct the mistakes. Based on our revised risk assessment,
in which we evaluated the risks that remain after promulgation of the
original MACT standards, as well as the MACT standards for small glycol
dehydrators in this final rule, we have determined that the risks for
the Oil and Gas Transmission and Storage major source category are
acceptable and that the MACT standards (including those promulgated
here) provide an ample margin of safety. Further, we are retaining the
0.9 Mg/yr benzene compliance alternative, which we had proposed to
remove based on our incorrect conclusion that it was driving the risk
for this major source category. We agree with the commenter that
removal of the 0.9 Mg/yr benzene compliance alternative does not reduce
risks for this major source category. Because we are retaining this
compliance alternative, we need not address the comment on the cost
effectiveness of removing this alternative.
C. Major Comments Concerning the Technology Review
Comment: One commenter states that, in conducting an 8-year review,
the EPA must ``look back'' at the earlier standard and ascertain
whether: (1) The standard was adopted using procedures that comply with
the law as it has come to be interpreted by the courts; (2) the EPA had
sufficiently accurate and comprehensive data at the time of the initial
standard setting respecting the emissions profile of the category and
properly identified the best performing unit(s); and (3) the EPA had
properly used the available data.
The commenter states the EPA then must ``look around'' using
currently available data and determine whether: (1) The emissions
profile of the industry has changed in a way that would substantially
affect the MACT floor calculations (the commenter adds that this
includes consideration of any increase in the number of good performing
units available for use in the existing source MACT floor calculation
and in the performance of the best performing unit); (2) data gaps or
uncertainties that affected the earlier decision have been resolved in
the interim or can be resolved using new information available to the
agency; (3) costs or other factors have changed in a way that would
substantially affect the ``beyond-the-floor'' determination; (4) the
use of improved practices, processes or technologies (including
improvements in the performance of existing technologies) has become
more prevalent than at the time of the initial standard setting; or (5)
whether newer regulatory requirements, work practices or emission
limitations (including state and local jurisdiction air pollution
standards and federal enforcement actions), which are more stringent
than the existing CAA section 112(d) standard, have shown the
achievement or achievability of greater emission reductions than the
existing standard requires.
Response: As explained in the preamble to the proposed rule, our
technology review 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 at issue here. We first reviewed the available
information. In this regard, we reviewed a variety of sources of data,
including data obtained in subsequent air toxics rules to see if any
practices, processes and control technologies
[[Page 49532]]
considered in these actions could be applied to emission sources in the
source categories at issue here. We also consulted the EPA's Reasonably
Available Control Technology (RACT)/Best Available Control Technology
(BACT)/Lowest Achievable Emission Rate (LAER) Clearinghouse (RBLC) and
the Natural Gas STAR program. At proposal, we explained that we
consider 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.
The commenter views CAA section 112(d)(6) differently. It appears
to argue that CAA section 112(d)(6) requires that the EPA recalculate
the MACT based on current data and technology. The same argument was
posed to the District of Columbia Circuit, and the Court ``[did] not
think that the words `review, and revise as necessary' can be construed
reasonably as imposing any such obligation.'' NRDC v. EPA, 529 F.3d
1077, 1084 (D.C. Cir. 2008). Thus, contrary to the commenter's
assertion, the EPA is not required pursuant to CAA section 112(d)(6) to
re-calculate the floors it set in 1999.
To the extent the commenter is arguing that CAA section 112(d)(6)
mandates that the EPA correct any deficiency in an underlying MACT
standard when it conducts the ``technology review'' under that section,
we disagree. We believe that CAA section 112 does not expressly address
this issue, and the EPA has discretion in determining how to address a
purported flaw in a promulgated standard. CAA section 112(d)(6)
provides that the agency must review and revise ``as necessary.'' The
``as necessary'' language must be read in the context of the provision,
which focuses on the review of developments that have occurred since
the time of the original promulgation of the MACT standard and thus
should not be read as a mandate to correct flaws that existed at the
time of the original promulgation.
In several recent rulemakings, we have chosen to fix underlying
defects in existing MACT standards under CAA sections 112(d)(2) and
(3), the provisions that directly govern the initial promulgation of
MACT standards (see National Emission Standards for Hazardous Air
Pollutants From Petroleum Refineries, October 28, 2009, 74 FR 55670;
and National Emission Standards for Hazardous Air Pollutants: Group I
Polymers and Resins; Marine Tank Vessel Loading Operations;
Pharmaceuticals Production; and the Printing and Publishing Industry,
April 21, 2011, 76 FR 22566). We believe that our approach is
reasonable because using those provisions ensures that the process and
considerations are those associated with initially establishing a MACT
standard, and it is reasonable to make corrections following the
process that would have been followed if we had not made an error at
the time of the original promulgation. As explained elsewhere, we are
not finalizing MACT standards for the subcategory of storage vessels
without the PFE, which were unregulated in the 1999 rule, because after
evaluating the available data and comments received, we believe that we
need additional data in order to set an emission standard for these
vessels. We are, however, finalizing MACT standards under CAA sections
112(d)(2) and (3) for the subcategory of small glycol dehydration
units.
With regard to our CAA section 112(d)(6) review, we found no
significant developments in practices, processes and control
technologies for reducing emissions from large glycol dehydrators and
storage vessels with PFE.\29\ Accordingly, we are not revising these
standards under CAA section 112(d)(6).
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\29\ See footnote 25.
---------------------------------------------------------------------------
The EPA also conducted a technology review evaluating various
options for controlling HAP emissions from equipment leaks. As
described in the proposed rule (76 FR 52784), we evaluated advancements
in controlling this emissions source since the original standards were
promulgated, including the emission reduction potential and associated
cost-effectiveness of these advancements. As a result of our review, we
revised the leak definition for valves at natural gas processing plants
to 500 ppm, thus, requiring the application of the LDAR requirement at
this lower detection level. As discussed above, the commenter appears
to be arguing that the EPA must redo the MACT floor and beyond-the-
floor analysis under CAA sections 112(d)(2) and (3) within its CAA
section 112(d)(6) technology review, which we disagree.
Comment: One commenter states that the EPA's technology review for
storage vessel control technologies is limited and makes incorrect
assumptions. The commenter contends that without further support, the
public cannot understand and the EPA cannot justify its proposed
decision; therefore, the EPA's proposal is arbitrary and capricious.
The commenter adds that the EPA must conduct an updated beyond-the-
floor analysis for storage vessels, by determining the ``maximum degree
of reduction in emissions'' that is achievable, as required under CAA
section 112(d)(2). The commenter states that the proposed rule fails to
provide any discussion of a beyond-the-floor determination for storage
vessels.
One commenter states that the EPA must examine advances in vapor
recovery unit technology and reconsider floating roof technology for
tanks containing liquids that do not have the PFE. The commenter
contends that the EPA improperly rejected technology advances and
developments in pollution prevention systems found in its own RBLC
database and employed by its own Natural Gas STAR partners.
Specifically, according to the commenter, the EPA failed to evaluate
the performance achieved by systems that use thermal or catalytic
oxidizers, either alone or in combination with condensers. According to
the commenter, the EPA's RBLC review identified a BACT determination
for dehydrator efficiency of 98 percent. The commenter also urges the
EPA to evaluate the use of combustion devices and vapor recovery units
that capture vent steam from the tank and turn it into a saleable
product by recompressing the hydrocarbon vapors. The commenter contends
that the EPA rejects technology advances by asserting that those
technologies were considered in the 1999 rulemaking, but fails to
provide support for its decision in either the record of the 1999
rulemaking or the current record. The commenter contends that the EPA
must provide a basis for its decisions and conclusions.
Response: For the reasons discussed in the prior response, the EPA
disagrees with the commenter's assertion that it must re-do the MACT
floor calculations, including the beyond-the-floor determination, for
the standards that the agency set in 1999. As to the technologies
identified by the commenter, they were in existence and considered by
the EPA at the time the EPA promulgated the original MACT
[[Page 49533]]
standards for storage vessels.30 31 In addition, we are not
finalizing control requirements for storage vessels without the PFE, as
described in section VII.A of this preamble. The record does not
support the assertion that the technologies identified by the commenter
have advanced in terms of HAP emission reduction or have become
significantly more cost effective. As explained in the preamble to the
proposed rule (76 FR 52785), we examined technologies that were similar
to the cover and route emissions to a control device that the MACT
floor requires and, thus, would not result in reductions beyond the
existing MACT requirements. Further, evaluation of technologies in the
RBLC did not produce any applicable practices, processes or control
technologies that were not considered during the original MACT for
storage vessels with flash emissions.\32\
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\30\ See footnote 25.
\31\ See EPA Legacy Docket A-94-04 MACT floor memos II-A-006 and
-007.
\32\ See footnote 25.
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D. Major Comments Concerning Notification, Recordkeeping and Reporting
Requirements
1. Annual Reports
Comment: One commenter requested that the EPA add a self-
certification requirement to the annual report similar to that used in
the title V program. The commenter recommended that the final rule
require the annual report to include a statement signed by a senior
official of the facility attesting to the truth, accuracy and
completeness of the report.
The commenter also requested that the EPA require that the annual
reports be submitted electronically to facilitate making the reports
publicly available. The commenter suggested using social media outlets,
smart phone applications and other electronic means to make the annual
reports readily available.
Response: The EPA agrees that self-certification is an important
mechanism for assuring the public that the information submitted by
each facility is accurate. In addition, the title V program has
successfully employed self-certification for since its inception.
Therefore, we are requiring self-certification, based on requirements
in the title V program, in the final rule.
While we agree that having annual reports readily available to the
public is a desirable goal, we did not identify any reporting programs
or electronic databases that may be used for this purpose without
significant modification. Therefore, we are not requiring annual
reports to be submitted electronically, but we will continue to
evaluate this option in the future.
2. Electronic Reporting of Emissions Data
Several commenters raised similar issues regarding reporting of
emissions data under the NESHAP as under the NSPS, described supra, and
our responses there apply equally here. Please see comments and
responses in section IX.F.3 of this preamble.
XI. What are the cost, environmental and economic impacts of the final
NESHAP and NSPS amendments?
A. What are the air 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 final amendments to 40 CFR part
63, subpart HH and 40 CFR part 63, subpart HHH are based on the
estimated population in 2008. Under the finalized limits for glycol
dehydration units, we have estimated that the HAP emissions reductions
will be 670 tons for existing units subject to the final 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.
The primary baseline used for the impacts analysis of our NSPS for
completions of hydraulically fractured natural gas wells takes into
account REC conducted pursuant to state regulations covering these
operations and estimates of REC performed voluntarily. To account for
REC performed in regulated states, the EPA subsumed emissions
reductions and compliance costs in states where these completion-
related emissions are already controlled into the baseline.
Additionally, based on public comments and reports to the EPA's Natural
Gas STAR program, the EPA recognizes that some producers conduct well
completions using REC techniques voluntarily for economic and/or
environmental objectives as a normal part of business. To account for
emissions reductions and costs arising from voluntary implementation of
pollution controls, the EPA used information on total emission
reductions reported to the EPA by partners of the EPA Natural Gas STAR.
This estimate of this voluntary REC activity in the absence of
regulation is also included in the baseline.\33\ More detailed
discussion on the derivation of the baseline is presented in a
technical memorandum in the docket, as well as in the Regulatory Impact
Analysis (RIA).
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\33\ Voluntary short-term actions (such as REC) are challenging
to capture accurately in a prospective analysis, as such, reductions
are not guaranteed to continue. However, Natural Gas STAR represents
a nearly 20-year voluntary initiative with participation from 124
natural gas companies operating in the United States, including 28
producers, over a wide historical range of natural gas prices. This
unique program and dataset, the significant impact of voluntary REC
on the projected cost and emissions reductions (due to significant
REC activity), and the fact that REC can actually increase natural
gas recovered from natural gas wells (offering a clear incentive to
continue the practice), led the agency to conclude that it was
appropriate to estimate these particular voluntary actions in the
baseline for this rule.
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Additionally, in the RIA, we provide summary-level estimates of
emissions reductions and engineering compliance costs for a case where
no voluntary REC are assumed to occur. This alternative case is
presented in order to show impacts if conditions were such that REC
were no longer performed on a voluntary basis, but, rather, were
compelled by the regulation, and serves, in part, to capture the
inherent uncertainty in projecting voluntary activity into the future.
As such, this alternative case establishes the full universe of
emissions reductions that are guaranteed by this NSPS (those that are
required to occur under the rule, including those that would likely
occur voluntarily). While the primary baseline may better represent
actual costs (and emissions reductions) beyond those already expected
under business as usual, the alternative case better captures the full
amount of emissions reductions where the NSPS acts as a backstop to
ensure that emission reduction practices occur (practices covered by
this rule).
Under the final NSPS, we have estimated that the emissions
reductions to be about 190,000 tons VOC affected facilities subject to
the NSPS. The NSPS is also expected to concurrently reduce 1.0 million
tons methane and 11,000 tons HAP. We estimate that direct reductions in
HAP, methane and VOC for the final rules combined total about 12,000
tons, 1.0 million tons and 190,000 tons, respectively. If voluntary
action is not deducted from the NSPS baseline, the emissions reductions
achieved by the final NSPS in HAP, methane and VOC are estimated at
[[Page 49534]]
about 19,000 tons, 1.7 million tons and 290,000 tons, respectively.
The EPA received several comments regarding the emission factor
selected to calculate whole gas emissions (and the associated VOC
emissions) from hydraulically fractured well completions. Comments
focused on the data behind the emission factor, what the emission
factor is intended to represent and the procedures used to develop the
emission factor from the selected data sets. We reviewed all
information received and have decided to retain the data set and the
analysis conducted to develop the emission factor of 9,000 thousand
cubic feet (Mcf) per completion. More detailed discussion is presented
in a technical memorandum on this subject in the docket.
B. 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 environmental controls
analyzed under the final NESHAP amendments and final NSPS.
The final NESHAP amendments and final 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 final standards
will result in net annual costs savings of about $11 million (in 2008
dollars) 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.
C. What are the cost impacts?
The estimated total capital cost to comply with the final
amendments to 40 CFR part 63, subpart HH for major sources in the Oil
and Natural Gas Production source category is approximately $2.6
million. The total capital cost for the final 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 $140,000. All
costs are in 2008 dollars.
The total estimated net annual cost to industry to comply with the
final amendments to 40 CFR part 63, subpart HH for major sources in the
Oil and Natural Gas Production source category is approximately $3.3
million. The total net annual cost for final 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 $180,000.
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 final NSPS is
approximately $25 million in 2008 dollars. The total estimated net
annual cost to industry to comply with the final NSPS is estimated to
be approximately $170 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
final 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/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 43 million Mcf (43 billion
cubic feet) of natural gas and 160,000 barrels of condensate are
estimated to be recovered by control requirements in 2015. Using the
price assumptions, the estimated revenues from natural gas and
condensate recovery are approximately $180 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 final NSPS to be about
$15 million. Totals may not sum due to independent rounding.
If voluntary action is not deducted from the baseline, capital
costs for the NSPS are estimated at $25 million and annualized costs
without revenues from product recovery for the NSPS are estimated at
$330 million. In this scenario, given the assumptions about product
prices, estimated revenues from product recovery are $350 million,
yielding an estimated cost of savings of about $22 million.
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 final NSPS.
At $4.22/Mcf, the price forecast reported in the 2011 Annual Energy
Outlook in 2008 dollars, the annualized cost savings for the final NSPS
are estimated at about $24 million. As indicated by this difference,
the 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 final NSPS breaks-even
from an estimated engineering costs perspective is around $3.66/Mcf. A
$1/Mcf change in the wellhead natural gas price leads to a $43 million
change in the annualized engineering costs of the final NSPS.
Consequently, annualized engineering costs estimates would increase to
about $29 million under a $3/Mcf price or decrease to about -$58
million under a $5/Mcf price. For further details on this sensitivity
analysis, please refer the RIA for this rulemaking located in the
docket.
D. What are the economic impacts?
The analysis of energy system impacts EPA performed using the
United States Department of Energy's (DOE) National Energy Modeling
System (NEMS) shows that domestic natural gas production is not likely
to change in 2015 as a result of the final rules, the year used in the
RIA to analyze impacts. Average natural gas prices are also not
estimated to change in response to the final rules. Domestic crude oil
production is not expected to change, while average crude oil prices
are estimated to decrease slightly (about $0.01/barrel or about 0.01
percent at the wellhead for onshore production in the lower 48 states).
All prices are in 2008 dollars. The NEMS-based analysis estimates in
the year of analysis, 2015, that net imports of natural gas and crude
oil will not change.
E. What are the benefits of this final rule?
The final 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 final
rules combined are anticipated to reduce 12,000 tons of HAP, 190,000
tons of VOC (a precursor to both PM (2.5 microns and less)
(PM2.5) and ozone formation) and 1.0 million tons of methane
(a GHG and a precursor to global ozone formation). These pollutants are
associated with
[[Page 49535]]
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
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.\34\ In addition to health improvements, there will
be improvements in visibility effects, ecosystem effects and climate
effects, as well as additional product recovery.
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\34\ Previous studies have estimated the monetized benefits-per-
ton of reducing VOC emissions associated with the effect that those
emissions have on ambient PM2.5 levels and the health
effects associated with PM2.5 exposure (Fann, Fulcher,
and Hubbell, 2009). While these ranges of benefit-per-ton estimates
provide useful context for the break-even analysis, the geographic
distribution of VOC emissions from the oil and gas sector are not
consistent with emissions modeled in Fann, Fulcher, and Hubbell
(2009). In addition, the benefit-per-ton estimates for VOC emission
reductions in that study are derived from total VOC emissions across
all sectors. Coupled with the larger uncertainties about the
relationship between VOC emissions and PM2.5 and the
highly localized nature of air quality responses associated with HAP
and VOC reductions, these factors lead us to conclude that the
available VOC benefit-per-ton estimates are not appropriate to
calculate monetized benefits of these rules, even as a bounding
exercise.
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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. VOC emissions are
precursors to both PM2.5 and ozone formation. As documented
in previous analyses (U.S. EPA, 2006 \35\ and U.S. EPA, 2010 \36\),
exposure to PM2.5 and ozone is associated with significant
public health effects. PM2.5 is associated with health
effects, including premature mortality for adults and infants,
cardiovascular morbidity such as heart attacks, and respiratory
morbidity such as asthma attacks, acute and chronic bronchitis,
hospital admissions and emergency room visits, work loss days,
restricted activity days and respiratory symptoms, as well as
visibility impairment.\37\ Ozone is associated with health effects,
including hospital and emergency department visits, school loss days
and premature mortality, as well as injury to vegetation and climate
effects.\38\
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\35\ 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.
\36\ 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.
\37\ 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.
\38\ 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://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 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
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.\39\ 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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\39\ U.S. EPA (2011), 2011 U.S. Greenhouse Gas Inventory Report
Executive Summary available on the internet at http://epa.gov/climatechange/emissions/downloads11/US-GHG-Inventory-2011-Executive-Summary.pdf, accessed 02/13/12.
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This rulemaking requires emission control technologies and
regulatory alternatives that will significantly decrease HAP and VOC
emissions from the oil and natural gas sector in the United States. As
a co-benefit, the emission control measures the industry will use to
reduce HAP and VOC emissions will also decrease methane emissions. The
NESHAP Amendments and the NSPS combined are expected to reduce methane
emissions annually by about 1.0 million short tons or about 19 million
metric tons CO2e. After considering the secondary impacts of
this rule as 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 18 million metric tons CO2e. The
methane reductions represent about 7 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). 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 4 million typical
passenger cars off the road or eliminating electricity use from about 2
million typical homes each year.\40\
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\40\ U.S. EPA. Greenhouse Gas Equivalency Calculator available
at: http://www.epa.gov/cleanenergy/energy-resources/calculator.html,
accessed 04/09/12.
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The EPA recognizes that the methane reductions from this rule will
provide for significant economic climate benefits to society just
described. However, the 2009-2010 Interagency Social Cost of Carbon
Work Group did not produce directly modeled estimates of the social
cost of methane. In the absence of direct model estimates from the
interagency analysis, the EPA has used a ``global warming potential
(GWP) approach'' to estimate the dollar value of this rule's methane
co-benefits. Specifically, the EPA converted methane to CO2
equivalents using the GWP of methane, then multiplied these
CO2 equivalent emission reductions by the social cost of
carbon developed by the Interagency Social Cost of Carbon Work Group.
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
[[Page 49536]]
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.\41\ Applying this approach to the methane reductions
estimated for the NESHAP Amendments and NSPS, the 2015 climate co-
benefits vary by discount rate and range from about $100 million to
approximately $1.3 billion; the mean social cost of carbon at the 3-
percent discount rate results in an estimate of about $440 million in
2015.\42\
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\41\ 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 02/12/12.
\42\ The ratio of domestic to global benefits of emission
reductions varies with key parameter assumptions. See Interagency
Working Group on Social Cost of Carbon. 2010. Technical Support
Document: Social Cost of Carbon for Regulatory Impact Analysis Under
Executive Order 12866.
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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.
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 the 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.\43\ 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 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 the GWP of 21 from the IPCC Second
Assessment Report to estimate the methane climate co-benefits for this
oil and gas rule. The EPA uses the 21 GWP in order to provide estimates
more consistent with global GHG inventories, which currently use GWP
from the IPCC Second Assessment Report, and with the US GHG Reporting
program. See the Regulatory Impact Analysis for further details.
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\43\ 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.
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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.
For the final NESHAP amendments, a break-even analysis suggests
that HAP emissions would need to be valued at $5,200 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 final 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 $2,900 per ton or the methane
emissions would need to be valued at $8,300 per ton for the co-benefits
to exceed the costs. All estimates are in 2008 dollars. For the final
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),\44\ 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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\44\ 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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XII. Statutory and Executive Order Reviews
A. Executive Order 12866, Regulatory Planning and Review and Executive
Order 13563, Improving Regulation and Regulatory Review
Under section 3(f)(1) of 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 $100 million or more. Accordingly, the EPA submitted
this action to the Office of Management and Budget (OMB) for review
under Executive Order 12866 and Executive Order 13563 (76 FR 3821,
January 21, 2011), and any changes made in response to OMB
recommendations have been documented in the docket for this action.
In addition, the EPA prepared a Regulatory Impact Analysis (RIA) of
the potential costs and benefits associated with this action. The RIA
available in the docket describes in detail the empirical basis for the
EPA's assumptions and characterizes the various sources of
uncertainties affecting the estimates below. Table 7 shows the results
of the cost and benefits analysis for these final rules.
[[Page 49537]]
Table 7--Summary of the Monetized Benefits, Social Costs and Net Benefits for the Final Oil and Natural Gas NSPS
and NESHAP Amendments in 2015
[Millions of 2008$] \1\
----------------------------------------------------------------------------------------------------------------
Final NSPS and NESHAP
Final NSPS Final NESHAP amendments amendments combined
----------------------------------------------------------------------------------------------------------------
Total Monetized Benefits \2\......... N/A.................... N/A.................... N/A.
Total Costs \3\...................... -$15 million........... $3.5 million........... -$11 million.
Net Benefits......................... N/A.................... N/A.................... N/A.
Non-monetized Benefits \4\........... 11,000 tons of HAP..... 670 tons of HAP........ 12,000 tons of HAP.
190,000 tons of VOC.... 1,200 tons of VOC...... 190,000 tons of VOC.
1.0 million tons of 420 tons of methane.... 1.0 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 particulate matter (PM) as well as climate effects associated
with methane, we have determined that quantification of those benefits and co-benefits cannot be accomplished
for this rule in a defensible way. This is not to imply that there are no benefits or co-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
final NSPS reflects the inclusion of revenues from additional natural gas and hydrocarbon condensate recovery
that are estimated as a result of the NSPS. Possible explanations for why there appear to be negative cost
control technologies are discussed in the engineering costs analysis section in the RIA.
\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.
The specific control technologies for the final NSPS are anticipated to have minor secondary disbenefits,
including an increase of 1.1 million tons of carbon dioxide (CO2), 550 tons of nitrogen oxides (NOX), 19 tons
of PM, 3,000 tons of CO and 1,100 tons of total hydrocarbons (THC), as well as emission reductions associated
with the energy system impacts. The specific control technologies for the NESHAP are anticipated to have minor
secondary disbenefits, but the EPA was unable to estimate these secondary disbenefits. The net CO2-equivalent
emission reductions are 18 million metric tons.
B. Paperwork Reduction Act
The information collection requirements in this rule have been
submitted for approval to the Office of Management and Budget (OMB)
under the Paperwork Reduction Act, 44 U.S.C. 3501, et seq. The
information collection requirements are not enforceable until OMB
approves them.
The ICR documents prepared by the EPA have been assigned EPA ICR
numbers 2437.01, 2438.01, 2439.01 and 2440.01. The information
requirements 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 CAA section 114 (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. This final rule requires 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.
When a malfunction occurs, sources must report them according to
the applicable reporting requirements of 40 CFR part 63, subpart HH or
40 CFR part 63, subpart HHH. An affirmative defense to civil penalties
for exceedances of emission limits that are caused by malfunctions is
available to a source if it can demonstrate that certain criteria and
requirements are satisfied. 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 reasonable preventable, and not caused by
poor maintenance and/or careless operation) and where the source took
necessary actions to minimize emissions. In addition, the source must
meet certain notification and reporting requirements. For example, the
source must prepare a written root cause analysis and submit a written
report to the Administrator documenting that it has met the conditions
and requirements for assertion of the affirmative defense.
For this rule, the EPA is adding affirmative defense to the
estimate of burden in the ICR. To provide the public with an estimate
of the relative magnitude of the burden associated with an assertion of
the affirmative defense position adopted by a source, the EPA has
provided administrative adjustments to this ICR that shows what the
notification, recordkeeping and reporting requirements associated with
the assertion of the affirmative defense might entail. The EPA's
estimate for the required notification, reports, and records, including
the root cause analysis, associated with a single incident totals
approximately totals $3,141 and is based on the time and effort
required of a source to review relevant data, interview plant
employees, and document the events surrounding a malfunction that has
caused an exceedance of an emission limit. The estimate also includes
time to produce and retain the record and reports for submission to the
EPA. The EPA provides this illustrative estimate of this burden,
because these costs are only incurred if there has been a violation,
and a source chooses to take advantage of the affirmative defense.
The EPA provides this illustrative estimate of this burden because
these costs are only incurred if there has been a violation and a
source chooses to take advantage of the affirmative defense. Given the
variety of circumstances under which malfunctions could occur, as well
as differences among sources' operation and maintenance practices, we
cannot reliably predict the severity and frequency of malfunction-
related excess emissions events for a particular source. It is
important to note that the
[[Page 49538]]
EPA has no basis currently for estimating the number of malfunctions
that would qualify for an affirmative defense. Current historical
records would be an inappropriate basis, as source owners or operators
previously operated their facilities in recognition that they were
exempt from the requirement to comply with emissions standards during
malfunctions. Of the number of excess emissions events reported by
source operators, only a small number would be expected to result from
a malfunction (based on the definition above), and only a subset of
excess emissions caused by malfunctions would result in the source
choosing to assert the affirmative defense. Thus, we believe the number
of instances in which source operators might be expected to avail
themselves of the affirmative defense will be extremely small.
For this reason, we estimate a total of 39 such occurrences for all
sources subject to 40 CFR part 63, subpart HH, a total of three such
occurrences for all sources subject to 40 CFR part 63, subpart HHH, and
a total of 6 such occurrences for all sources subject to 40 CFR part
60, subparts KKK and LLL over the 3-year period covered by this ICR. We
expect to gather information on such events in the future, and will
revise this estimate as better information becomes available.
The annual monitoring, reporting, and recordkeeping burden for this
collection (averaged over the first 3 years after the effective date of
the standards) is estimated to be $20.1 million. This includes 384,866
labor hours per year at a total labor cost of $19.5 million per year,
and annualized capital costs of $0.36 million, and annual operating and
maintenance costs of $0.20 million. This estimate includes initial and
annual performance tests, semiannual excess emission reports,
developing a monitoring plan, notifications and recordkeeping. All
burden estimates are in 2008 dollars and represent the most cost-
effective monitoring approach for affected facilities. 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. When these ICR
are approved by OMB, the agency will publish a technical amendment to
40 CFR part 9 in the Federal Register to display the OMB control
numbers for the approved information collection requirements contained
in the final rule.
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 as defined by NAICS codes 211111,
211112, 221210, 486110 and 486210; 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.
For the final NSPS, the EPA performed an analysis for impacts on a
sample of expected affected small entities by comparing compliance
costs to entity revenues. The baseline used in this analysis takes into
account REC conducted pursuant to state regulations covering these
operations and estimates of REC performed voluntarily. To account for
REC performed in regulated states, the EPA subsumed emissions
reductions and compliance costs in states where these completion-
related emissions are already controlled into the baseline.
Additionally, based on public comments and reports to the EPA's Natural
Gas STAR program, the EPA recognizes that some producers conduct well
completions using REC techniques voluntarily for economic and/or
environmental objectives as a normal part of business. To account for
emissions reductions and costs arising from voluntary implementation of
pollution controls, the EPA used information on total emission
reductions reported to the EPA by partners of the EPA Natural Gas STAR.
This estimate of this voluntary REC activity in the absence of
regulation is also included in the baseline. More detailed discussion
on the derivation of the baseline is presented in a technical
memorandum in the docket, as well as in the RIA.
Based upon the analysis in the RIA, which is in the Docket, when
revenue from additional natural gas product recovered is not included,
we estimate that 123 of the 127 small firms analyzed (97 percent) are
likely to have impacts less than 1 percent in terms of the ratio of
annualized compliance costs to revenues. Meanwhile, four firms (3
percent) are likely to have impacts greater than 1 percent. Three of
these four firms are likely to have impacts greater than 3 percent.
However, when revenue from additional natural gas product recovery is
included, we estimate that none of the analyzed firms will have an
impact greater than 1 percent.
For the final NESHAP amendments, we estimate that 11 of the 35
firms (31 percent) that own potentially affected facilities are small
entities. The EPA performed an analysis for impacts on all expected
affected small entities by comparing compliance costs to entity
revenues. Among the small firms, none are likely to have impacts
greater than 1 percent in terms of the ratio of annualized compliance
costs to revenues.
After considering the economic impact of the combined NSPS and
NESHAP amendments on small entities, I certify this action will not
have a significant impact on a substantial number of small entities
(SISNOSE). While both the NSPS and NESHAP amendment would individually
result in a no SISNOSE finding, the EPA performed an additional
analysis in order to certify the rule in its entirety. This analysis
compared compliance costs to entity revenues for the total of all the
entities affected by the NESHAP amendments and the sample of entities
analyzed for the NSPS. When revenues from additional natural gas
product sales are not included, 132 of the 136 small firms (97 percent)
in the sample are likely to have impacts of less than 1 percent in
terms of the ratio of annualized compliance costs to revenues.
Meanwhile, four firms (3 percent) are likely to have impacts greater
than 1 percent. Three of these four firms are likely to have impacts
greater than 3 percent. When revenues from additional natural gas
product sales are included, none of the 136 small firms (100 percent)
are likely to have impacts greater than 1 percent.
Our 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
[[Page 49539]]
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 occur over a short span of time, during which the
additional product recovery is also accomplished and payments for
recovered products are settled.
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.
D. Unfunded Mandates Reform Act
This final action does not contain a federal mandate under the
provisions of Title II of the Unfunded Mandates Reform Act of 1995
(UMRA), 2 U.S.C. 1531-1538 for state, local, and tribal governments, in
the aggregate, or to the private sector. The action would not result in
expenditures of $100 million or more for state, local, and tribal
governments, in the aggregate, or to the private sector in any 1 year.
Thus, this final rule is not subject to the requirements of sections
202 or 205 of UMRA.
This final 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 because it contains
no requirements that apply to such governments nor does it impose
obligations upon them.
E. Executive Order 13132: Federalism
This action 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. These final rules primarily affect
private industry, and do not impose significant economic costs on state
or local governments. On the contrary, we believe the modification
provisions discussed in section IX.A for well completions conducted at
gas wells constructed on or before August 23, 2011, will reduce
permitting burden borne by the States. These provisions will result in
fewer sources becoming affected facilities under the NSPS while
achieving emission reductions beginning October 15, 2012 equal to those
achieved by new sources beginning January 1, 2015. Thus, Executive
Order 13132 does not apply to this action.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
Subject to the Executive Order 13175 (65 FR 67249, November 9,
2000) the EPA may not issue a regulation that has tribal implications,
that imposes substantial direct compliance costs, and that is not
required by statute, unless the Federal government provides the funds
necessary to pay the direct compliance costs incurred by tribal
governments, or the EPA consults with tribal officials early in the
process of developing the proposed regulation and develops a tribal
summary impact statement.
The EPA has concluded that this action will not have tribal
implications because it doesn't impose a significant cost to the tribal
government. However, there are significant tribal interests because of
the growth of the oil and gas production industry in Indian country.
The EPA initiated a consultation process with tribal officials
early in the process of developing this regulation to permit them to
have meaningful and timely input into its development. During the
consultation process, the EPA conducted outreach and information
meetings prior to the proposal in 2010. The EPA met with the Inter
Tribal Environmental Council, which include many of the Region VI
tribes, The Tribal leadership summit in Region X, and Tribal Energy
Conference hosted by Ft. Belknap, and the National Tribal Forum.
After the proposal was published, letters were sent to all tribal
leaders offering to consult on a government-to-government basis on the
rule. As part of the consultation process and in response to these
letters, an outreach call was held on October 12, 2011. Tribes that
participated on this call were: Fond du Lac Band of Lake Superior
Chippewa, Fort Belknap Indian Community, Forest County Potawatomi
Community, Southern Ute Indian Tribe, and Pueblo of Santa Clara.
In this meeting the tribes were presented the information in the
proposal. The tribes asked general clarifying questions but did not
provide specific comments. Comments on the proposal were received from
an affiliate of the Southern Ute Indian Tribe. The commenter expressed
concern about the impacts of the rule on natural gas and oil production
operations on the Southern Ute Indian reservation and requested
additional time to evaluate the impacts. In response to this and other
requests, the comment period was extended. More specific comments can
be found in the docket.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
This action 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 action would not relax the
control measures on existing regulated sources. The EPA's risk
assessments (included in the docket for this final rule) demonstrate
that the existing regulations are associated with an acceptable level
of risk and provide an ample margin of safety to protect public health.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action is not a ``significant energy action'' as defined in
Executive Order 13211 (66 FR 28355, May 22, 2001), because it is not
likely to have a significant adverse effect on the supply,
distribution, or use of energy. These final 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 final NESHAP
amendments are unlikely to have a significant adverse effect on the
supply, distribution, or use of energy. As such, the final NESHAP
amendments are not ``significant energy actions'' as defined in
Executive Order 13211, (66 FR 28355, May 22, 2001). The final NSPS is
also unlikely to have a significant adverse effect on the supply,
distribution, or use of energy. As such, the final NSPS is not a
``significant energy action'' as defined in Executive Order 13211 (66
FR 28355, May 22, 2001).
The basis for these determinations is as follows. 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 final NSPS also captures saleable condensates. The
revenues from additional natural gas and condensate recovery are
expected to offset the costs of implementing the final rules.
We use the NEMS to estimate the impacts of the combined final rules
on
[[Page 49540]]
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 DOE and is used to produce
the Annual Energy Outlook, a reference publication that provides
detailed forecasts of the United States energy economy.
Based on public comments and reports to EPA's Natural Gas STAR
program, the EPA recognizes that some producers conduct well
completions using REC techniques, which are required by the final NSPS
for certain completions of hydraulically fractured and refractured
natural gas wells, voluntarily based upon economic and environmental
objectives. The baseline used for the energy system impacts analysis
takes into account REC conducted pursuant to state regulations covering
these operations and estimates of REC performed voluntarily. To account
for REC performed in regulated states, the EPA subsumed emissions
reductions and compliance costs in states where these completion-
related emissions are already controlled into the baseline.
Additionally, based on public comments and reports to the EPA's Natural
Gas STAR program, the EPA recognizes that some producers conduct well
completions using REC techniques voluntarily for economic and/or
environmental objectives as a normal part of business. To account for
emissions reductions and costs arising from voluntary implementation of
pollution controls, the EPA used information on total emission
reductions reported to the EPA by partners of the EPA Natural Gas STAR.
This estimate of this voluntary REC activity in the absence of
regulation is also included in the baseline. More detailed discussion
on the derivation of the baseline is presented in a technical
memorandum in the docket, as well as in the RIA.
The analysis of energy system impacts for the final NSPS under the
primary baseline shows that domestic natural gas production is not
likely to change in 2015, the year used in the RIA to analyze impacts.
Average natural gas prices are also not estimated to change in response
to the final rules. Domestic crude oil production is not expected to
change, while average crude oil prices are estimated to decrease
slightly (about $0.01/barrel or about 0.01 percent at the wellhead for
onshore production in the lower 48 states). All prices are in 2008
dollars. The NEMS-based analysis estimates in the year of analysis,
2015, that net imports of natural gas and crude oil will not change.
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 final 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 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.
This final rulemaking involves technical standards. Three VCS were
identified as applicable for the purpose of these rules. The VCS ASTM
D6522-00 (2005), Standard Test Method for the Determination of Nitrogen
Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions From
Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers
and Process Heaters Using Portable Analyzers, is an acceptable
alternative to EPA Methods 3A and 10 for identifying nitrogen oxides,
carbon monoxide, and oxygen concentrations when the fuel is natural
gas. The VCS ASTM D6420-99 (2004), Test Method for Determination of
Gaseous Organic Compounds by Direct Interface Gas Chromatography/Mass
Spectrometry, is an acceptable alternative to EPA Method 18. The VCS
ANSI/ASME PTC 19.10-1981 (Part 10, Instruments and Apparatus), Flue and
Exhaust Gas Analyses is an acceptable alternative to EPA Methods 3B and
16A manual portion only, not the instrumental portion.
No potential VCS were identified for EPA Methods 1A, 2A, 2D, 21,
and 22.
During the search, if the title or abstract (if provided) of the
VCS described technical sampling and analytical procedures that were
similar to the EPA's reference method, the EPA ordered a copy of the
standard and reviewed it as a potential equivalent method. All
potential standards were reviewed to determine the practicality of the
VCS for this action. This review requires significant method validation
data that meet the requirements of EPA Method 301 for accepting
alternative methods or scientific, engineering and policy equivalence
to procedures in the EPA reference methods. The EPA may reconsider
determinations of impracticality when additional information is
available for particular VCS.
The search identified 18 other VCS that were potentially applicable
for these rules in lieu of the EPA reference methods. After reviewing
the available standards, the EPA determined that 18 candidate VCS (ASTM
D3154-00 (2006), ASTM D3464-96 (2007), ASTM D3796-90 (2004), ISO
10780:1994, ASME B133.9-1994 (2001), ANSI/ASME PTC 19.10-1981 Part 10,
ASTM D5835-95 (2007), ISO 10396:1993, ISO 12039:2001, ASTM D6522-00
(2005), CAN/CSA Z223.2-M86 (1999), CAN/CSA Z223.21-M1978, ASTM D3162-94
(2005), ASTM D4323-84 (2009), ASTM D6060-96 (2001), ISO 14965:2000(E),
EN 12619 (1999), ASTM D4855-97 (2002)) identified for measuring
emissions of pollutants or their surrogates subject to emission
standards in the rules would not be practical due to lack of
equivalency, documentation, validation data and other important
technical and policy considerations. Refer to the memorandum in the
docket for further details on the EPA's review of these VCS.
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 environmental justice. Its main provision
directs Federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice 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 final 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
[[Page 49541]]
human health or environmental effects on any population, including any
minority, low-income, or indigenous populations.
To examine the potential for any environmental justice issues that
might be associated with each source category, we evaluated the
percentages of various social, demographic, and economic groups within
the at-risk population living near the facilities where these source
categories are located and compared them to national averages. The
development of demographic analyses to inform the consideration of
environmental justice issues in the EPA rulemakings is an evolving
science.
The EPA conducted a demographic analysis, focusing on populations
within 50 km of any facility in each of the source categories that are
estimated to have HAP exposures which result in cancer risks of 1-in-1
million or greater or non-cancer hazard indices of 1 or greater based
on estimates of current HAP emissions. The results of this analysis are
documented in the technical report: Risk and Technology Review--
Analysis of Socio-Economic Factors for Populations Living Near Oil &
Natural Gas Production Facilities, located in the docket for this
rulemaking.
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 non-cancer 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.
To promote meaningful involvement, the EPA conducted three public
hearings on the proposal. The hearings were held in Pittsburgh,
Pennsylvania, on September 27, 2011, Denver, Colorado, on September 28,
2011, and Arlington, Texas, on September 29, 2011. A total of 261
people spoke at the three hearings and 735 people attended the
hearings. The attendees at the hearings included private citizens,
community-based and environmental organizations, industry
representatives, associations representing industry and local and state
government officials.
K. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801, et seq., as added by
the Small Business Regulatory Enforcement Fairness Act of 1996,
generally provides that before a rule may take effect, the agency
promulgating the rule must submit a rule report, which includes a copy
of the rule, to each House of the Congress and to the Comptroller
General of the United States. The EPA will submit a report containing
this final rule and other required information to the United States
Senate, the United States House of Representatives, and the Comptroller
General of the United States prior to publication of the final rule in
the Federal Register. A major rule cannot take effect until 60 days
after it is published in the Federal Register. This action is a ``major
rule'' as defined by 5 U.S.C. 804(2). The final rules will be effective
on October 15, 2012.
List of Subjects
40 CFR Part 60
Environmental protection, Air pollution control, Incorporation by
reference, Reporting and recordkeeping requirements, Volatile organic
compounds.
40 CFR Part 63
Environmental protection, Administrative practice and procedures,
Air pollution control, Hazardous substances, Incorporation by
reference, Reporting and recordkeeping requirements, Volatile organic
compounds.
Dated: April 17, 2012.
Lisa P. Jackson,
Administrator.
For the reasons set out in the preamble, title 40, chapter I of the
Code of Federal Regulations is amended as follows:
PART 60--[AMENDED]
0
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
0
2. Section 60.17 is amended by:
0
a. Revising paragraph (a) introductory text, (a)(7), (a)(86), (a)(91),
and (a)(92);
0
b. Adding paragraphs (a)(95), (a)(96), (a)(97), and (a)(98); and
0
c. Revising paragraph (h) introductory text and (h)(4) to read as
follows:
Sec. 60.17 Incorporations by reference.
* * * * *
(a) The following materials are available for purchase from at
least one of the following addresses: American Society for Testing and
Materials (ASTM), 100 Barr Harbor Drive, Post Office Box C700, West
Conshohocken, PA 19428-2959, Telephone (610) 832-9585, and are also
available at the following Web site: http://www.astm.org; or ProQuest,
789 East Eisenhower Parkway, Ann Arbor, MI 48106-1346, Telephone (734)
761-4700, and are also available at the following Web site: http://www.proquest.com.
* * * * *
(7) ASTM D86-96, Standard Test Method for Distillation of Petroleum
Products (Approved April 10, 1996), IBR approved for Sec. Sec. 60.562-
2(d), 60.593(d), 60.593a(d), 60.633(h) and 60.5401(f).
* * * * *
(86) ASTM D6522-00 (Reapproved 2005), Standard Test Method for
Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen
Concentrations in Emissions from Natural Gas-Fired Reciprocating
Engines, Combustion Turbines, Boilers, and Process Heaters Using
Portable Analyzers (Approved October 1, 2005), IBR approved for table 2
of subpart JJJJ of this part, and Sec. Sec. 60.5413(b) and (d).
* * * * *
(91) ASTM E169-93, Standard Practices for General Techniques of
Ultraviolet-Visible Quantitative Analysis (Approved May 15, 1993), IBR
approved for Sec. Sec. 60.485a(d), 60.593(b), 60.593a(b), 60.632(f)
and 60.5400(f).
(92) ASTM E260-96, Standard Practice for Packed Column Gas
Chromatography (Approved April 10, 1996), IBR approved for Sec. Sec.
60.485a(d), 60.593(b), 60.593a(b), 60.632(f), 60.5400(f) and
60.5406(b).
* * * * *
(95) ASTM D3588-98 (Reapproved 2003) Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density of
Gaseous Fuels (Approved May 10, 2003), IBR approved for Sec.
60.5413(d).
(96) ASTM D4891-89 (Reapproved 2006) Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion (Approved June 1, 2006), IBR approved for Sec. 60.5413(d).
(97) ASTM D1945-03 (Reapproved 2010), Standard Test Method for
Analysis of Natural Gas by Gas Chromatography (Approved January 1,
2010), IBR approved for Sec. 60.5413(d).
(98) ASTM D5504-08, Standard Test Method for Determination of
Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography
and Chemiluminescence (Approved June 15, 2008), IBR approved for Sec.
60.5413(d).
* * * * *
[[Page 49542]]
(h) The following material is available for purchase from the
American Society of Mechanical Engineers (ASME), Three Park Avenue, New
York, NY 10016-5990, Telephone (800) 843-2763, and are also available
at the following Web site: http://www.asme.org.
* * * * *
(4) 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. 60.56c(b), 60.63(f), 60.106(e), 60.104a(d), (h), (i) and
(j), 60.105a(d), (f) and (g), 60.106a(a), 60.107a(a), (c) and (d),
tables 1 and 3 of subpart EEEE, tables 2 and 4 of subpart FFFF, table 2
of subpart JJJJ, Sec. Sec. 60.4415(a), 60.2145(s) and (t), 60.2710(s),
(t) and (w), 60.2730(q), 60.4900(b) and 60.5220(b), tables 1 and 2 to
subpart LLLL, tables 2 and 3 to subpart MMMM, Sec. Sec. 60.5406(c) and
60.5413(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
0
3. The heading for Subpart KKK is revised to read as set forth above.
0
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
0
5. The heading for Subpart LLL is revised to read as set forth above.
0
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.
* * * * *
0
7. Add subpart OOOO, consisting of 60.5360 through 60.5430, 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 well 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 equipment leak standards apply to affected facilities
at an onshore natural gas processing plant?
60.5401 What are the exceptions to the equipment leak 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 gas well affected facility, my centrifugal compressor
affected facility, my reciprocating compressor affected facility, my
pneumatic controller affected facility, my storage vessel affected
facility, and my equipment leaks and sweetening unit affected
facilities at onshore natural gas processing plants?
60.5411 What additional requirements must I meet to determine
initial compliance for my closed vent systems routing emissions from
storage vessels or centrifugal compressor wet seal fluid degassing
systems?
60.5412 What additional requirements must I meet for determining
initial compliance with control devices used to comply with the
emission standards for my storage vessel or centrifugal compressor
affected facility?
60.5413 What are the performance testing procedures for control
devices used to demonstrate compliance at my storage vessel or
centrifugal compressor affected facility?
60.5415 How do I demonstrate continuous compliance with the
standards for my gas well 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?
60.5416 What are the initial and continuous cover and closed vent
system inspection and monitoring requirements for my storage vessel
or centrifugal compressor affected facility?
60.5417 What are the continuous control device monitoring
requirements for my storage vessel or centrifugal compressor
affected facility?
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 parts 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
commence construction, modification or reconstruction after August 23,
2011.
[[Page 49543]]
Sec. 60.5365 Am I subject to this subpart?
You are subject to the applicable provisions of this subpart if you
are the owner or operator of one or more of the onshore affected
facilities listed in paragraphs (a) through (g) of this section for
which you commence construction, modification or reconstruction after
August 23, 2011.
(a) Each gas well affected facility, which is a single natural gas
well.
(b) Each centrifugal compressor affected facility, which is a
single centrifugal compressor using wet seals that is located between
the wellhead and the point of custody transfer to the natural gas
transmission and storage segment. A centrifugal compressor located at a
well site, or an adjacent well site and servicing more than one well
site, is not an affected facility under this subpart.
(c) Each reciprocating compressor affected facility, which is a
single reciprocating compressor located between the wellhead and the
point of custody transfer to the natural gas transmission and storage
segment. A reciprocating compressor located at a well site, or an
adjacent well site and servicing more than one well site, is not an
affected facility under this subpart.
(d)(1) For the oil production segment (between the wellhead and the
point of custody transfer to an oil pipeline), each pneumatic
controller affected facility, which is a single continuous bleed
natural gas-driven pneumatic controller operating at a natural gas
bleed rate greater than 6 scfh.
(2) For the natural gas production segment (between the wellhead
and the point of custody transfer to the natural gas transmission and
storage segment and not including natural gas processing plants), each
pneumatic controller affected facility, which is a single continuous
bleed natural gas-driven pneumatic controller operating at a natural
gas bleed rate greater than 6 scfh.
(3) For natural gas processing plants, each pneumatic controller
affected facility, which is a single continuous bleed natural gas-
driven pneumatic controller.
(e) Each storage vessel affected facility, which is a single
storage vessel, located in the oil and natural gas production segment,
natural gas processing segment or natural gas transmission and storage
segment.
(f) The group of all equipment, except compressors, within a
process unit is an affected facility.
(1) Addition or replacement of equipment for the purpose of process
improvement that is accomplished without a capital expenditure shall
not by itself be considered a modification under this subpart.
(2) Equipment associated with a compressor station, dehydration
unit, sweetening unit, underground storage vessel, 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 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.
(3) The equipment within a process unit of an affected facility
located at onshore natural gas processing plants and described in
paragraph (f) 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 at onshore natural gas processing
plants 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
Sec. Sec. 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, 60.5410(g), 60.5415(g), and 60.5423 of this subpart.
(h) The following provisions apply to gas well facilities that are
hydraulically refractured.
(1) A gas well facility that conducts a well completion operation
following hydraulic refracturing is not an affected facility, provided
that the requirements of Sec. 60.5375 are met. For purposes of this
provision, the dates specified in Sec. 60.5375(a) do not apply, and
such facilities, as of October 15, 2012, must meet the requirements of
Sec. 60.5375(a)(1) through (4).
(2) A well completion operation following hydraulic refracturing at
a gas well facility not conducted pursuant to Sec. 60.5375 is a
modification to the gas well affected facility.
(3) Refracturing of a gas well facility does not affect the
modification status of other equipment, process units, storage vessels,
compressors, or pneumatic controllers located at the well site.
(4) Sources initially constructed after August 23, 2011, are
considered affected sources regardless of this provision.
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 October 15, 2012 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 well affected facilities?
If you are the owner or operator of a gas well affected facility,
you must comply with paragraphs (a) through (f) of this section.
(a) Except as provided in paragraph (f) of this section, for each
well completion operation with hydraulic fracturing begun prior to
January 1, 2015, you must comply with the requirements of paragraphs
(a)(3) and (4) of this section unless a more stringent state or local
emission control requirement is applicable; optionally, you may comply
with the requirements of paragraphs (a)(1) through (4) of this section.
For each new well completion operation with hydraulic fracturing begun
on or after January 1, 2015, you must comply with the requirements in
paragraphs (a)(1) through (4) of this section.
(1) For the duration of flowback, route the recovered liquids into
one or more storage vessels or re-inject the recovered liquids into the
well or another well, and route the recovered gas into a gas flow line
or collection system, re-inject the recovered gas into the well or
another well, use the recovered gas as an on-site fuel source, or use
the recovered gas for another useful purpose that a purchased fuel or
raw material would serve, with no direct release to the atmosphere. If
this is infeasible, follow the requirements in paragraph (a)(3) of this
section.
(2) All salable quality gas must be routed to the gas flow line as
soon as
[[Page 49544]]
practicable. In cases where flowback emissions cannot be directed to
the flow line, you must follow the requirements in paragraph (a)(3) of
this section.
(3) You must capture and direct flowback emissions to a completion
combustion device, except in conditions that may result in a fire
hazard or explosion, or where high heat emissions from a completion
combustion device may negatively impact tundra, permafrost or
waterways. Completion combustion devices must be equipped with a
reliable continuous ignition source over the duration of flowback.
(4) You have a general duty to safely maximize resource recovery
and minimize releases to the atmosphere during flowback and subsequent
recovery.
(b) You must maintain a log for each well completion operation at
each gas well affected facility. The log must be completed on a daily
basis for the duration of the well completion operation 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 well affected facilities as required by Sec. 60.5410.
(d) You must demonstrate continuous compliance with the standards
that apply to gas well 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)(1) For each gas well affected facility specified in paragraphs
(f)(1)(i) and (ii) of this section, you must comply with the
requirements of paragraphs (f)(2) and (3) of this section.
(i) Each well completion operation with hydraulic fracturing at a
gas well affected facility meeting the criteria for a wildcat or
delineation well.
(ii) Each well completion operation with hydraulic fracturing at a
gas well affected facility meeting the criteria for a non-wildcat low
pressure gas well or non-delineation low pressure gas well.
(2) You must capture and direct flowback emissions to a completion
combustion device, except in conditions that may result in a fire
hazard or explosion, or where high heat emissions from a completion
combustion device may negatively impact tundra, permafrost or
waterways. Completion combustion devices must be equipped with a
reliable continuous ignition source over the duration of flowback. You
must also comply with paragraphs (a)(4) and (b) through (e) of this
section.
(3) You must maintain records specified in Sec. 60.5420(c)(1)(iii)
for wildcat, delineation and low pressure gas 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 for each centrifugal compressor affected facility.
(a)(1) You must reduce VOC emissions from each centrifugal
compressor wet seal fluid degassing system by 95.0 percent or greater.
(2) If you use a control device to reduce emissions, you must equip
the wet seal fluid degassing system with a cover that meets the
requirements of Sec. 60.5411(b) and is connected through a closed vent
system that meets the requirements of Sec. 60.5411(a) to a control
device that meets the conditions specified in Sec. 60.5412.
(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
according to either paragraph (a)(1) or (2) of this section.
(1) 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
October 15, 2012, or the date of the most recent reciprocating
compressor rod packing replacement, whichever is later.
(2) Prior to 36 months from the date of the most recent rod packing
replacement, or 36 months from the date of startup for a new
reciprocating compressor for which the rod packing has not yet been
replaced.
(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) of this section are
exempt from this requirement.
(a) The requirements of paragraph (b) or (c) of this section are
not required if you determine that the use of a pneumatic controller
affected facility with a bleed rate greater than 6 standard cubic feet
per hour is required based on functional needs, including but not
limited to response time, safety and positive actuation.
(b)(1) Each pneumatic controller affected facility at a natural gas
processing plant must have a bleed rate of zero.
(2) Each pneumatic controller affected facility at a natural gas
processing plant must be tagged with the month and year of
installation, reconstruction or modification, and identification
information that allows traceability to the records for that pneumatic
controller as required in Sec. 60.5420(c)(4)(iv).
(c)(1) Each pneumatic controller affected facility constructed,
modified or reconstructed on or after October 15, 2013 at a location
between the wellhead and a natural gas processing plant must have a
bleed rate less than or equal to 6 standard cubic feet per hour.
(2) Each pneumatic controller affected facility at a location
between the wellhead and a natural gas processing plant must be tagged
with the month and year of installation, reconstruction or
modification, and identification information that allows traceability
to the records for that controller as required in Sec.
60.5420(c)(4)(iii).
(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?
Except as provided in paragraph (d) of this section, you must
comply with the standards in this section no later than October 15,
2013 for each storage vessel
[[Page 49545]]
affected facility constructed, modified or reconstructed after August
23, 2011, with VOC emissions equal to or greater than 6 tpy, as
determined in paragraph (a) of this section.
(a) Emissions determination--(1) Well sites with no other wells in
production. For each storage vessel constructed, modified or
reconstructed at a well site with no other wells in production, you
must determine the VOC emission rate for each storage vessel affected
facility using any generally accepted model or calculation methodology
within 30 days after startup, and minimize emissions to the extent
practicable during the 30-day period using good engineering practices.
For each storage vessel affected facility emitting more than 6 tpy VOC,
you must reduce VOC emissions by 95.0 percent or greater within 60 days
after startup.
(2) Well sites with one or more wells already in production. For
each storage vessel constructed, modified or reconstructed at a well
site with one or more wells already in production, you must determine
the VOC emission rate for each storage vessel affected facility using
any generally accepted model or calculation methodology upon startup.
For each storage vessel affected facility emitting more than 6 tpy VOC,
you must reduce VOC emissions by 95.0 percent or greater upon startup.
(b) Control requirements. (1) If you use a control device (such as
an enclosed combustion device or vapor recovery device) to reduce
emissions, you must equip the storage vessel with a cover that meets
the requirements of Sec. 60.5411(b) and is connected through a closed
vent system that meets the requirements of Sec. 60.5411(a) to a
control device that meets the conditions specified in Sec. 60.5412.
(2) If you use a floating roof to reduce emissions, you must meet
the requirements of Sec. 60.112b(a)(1) or (2) and the relevant
monitoring, inspection, recordkeeping, and reporting requirements in 40
CFR part 60, subpart Kb.
(c) Compliance, notification, recordkeeping, and reporting. (1) You
must demonstrate initial compliance with standards that apply to
storage vessel affected facilities as required by Sec. 60.5410.
(2) You must demonstrate continuous compliance with standards that
apply to storage vessel affected facilities as required by Sec.
60.5415.
(3) You must perform the required notification, recordkeeping, and
reporting as required by Sec. 60.5420.
(d) Exemptions. This section does not apply to storage vessels
subject to and controlled in accordance with the requirements for
storage vessels in 40 CFR part 60, subpart Kb, or 40 CFR part 63,
subparts G, CC, HH, WW, or HHH.
Sec. 60.5400 What equipment leak standards apply to affected
facilities at an onshore natural gas processing plant?
This section applies to the group of all equipment, except
compressors, within a process unit.
(a) You must comply with the requirements of Sec. Sec. 60.482-
1a(a), (b), and (d), 60.482-2a, and 60.482-4a through 60.482-11a,
except as provided in Sec. 60.5401.
(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 E169-93, E168-92, or
E260-96 (incorporated by reference as specified in Sec. 60.17) must be
used.
Sec. 60.5401 What are the exceptions to the equipment leak standards
for affected facilities at onshore natural gas processing plants?
(a) You may comply with the following exceptions to the provisions
of Sec. 60.5400(a) and (b).
(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 500 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 that does not have the 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) 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 D86-96 (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
[[Page 49546]]
D86-96 (incorporated by reference as specified in Sec. 60.17).
(g) An owner or operator may use the following provisions instead
of Sec. 60.485a(b)(2): A calibration drift assessment shall be
performed, at a minimum, at the end of each monitoring day. Check the
instrument using the same calibration gas(es) that were used to
calibrate the instrument before use. Follow the procedures specified in
Method 21 of appendix A-7 of this part, Section 10.1, except do not
adjust the meter readout to correspond to the calibration gas value.
Record the instrument reading for each scale used as specified in Sec.
60.486a(e)(8). Divide these readings by the initial calibration values
for each scale and multiply by 100 to express the calibration drift as
a percentage. If any calibration drift assessment shows a negative
drift of more than 10 percent from the initial calibration value, then
all equipment monitored since the last calibration with instrument
readings below the appropriate leak definition and above the leak
definition multiplied by (100 minus the percent of negative drift/
divided by 100) must be re-monitored. If any calibration drift
assessment shows a positive drift of more than 10 percent from the
initial calibration value, then, at the owner/operator's discretion,
all equipment since the last calibration with instrument readings above
the appropriate leak definition and below the leak definition
multiplied by (100 plus the percent of positive drift/divided by 100)
may be re-monitored.
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 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:
[GRAPHIC] [TIFF OMITTED] TR16AU12.000
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 10-3Mg/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 E260-96 (incorporated by
reference as specified in 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] TR16AU12.001
(2) You must use the level indicators or manual soundings to
measure the liquid sulfur accumulation rate in the product storage
vessels. 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] TR16AU12.002
Where:
E = emission rate of sulfur per run, kg/hr.
Ce = concentration of sulfur equivalent (SO\2+\ reduced
sulfur), g/dscm (lb/dscf).
Qsd = volumetric flow rate of effluent gas, dscm/hr
(dscf/hr).
[[Page 49547]]
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 or ANSI/ASME PTC 19.10-1981, Part 10 (manual portion
only) (incorporated by reference as specified in Sec. 60.17) 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.
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 vessels 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 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)(1).
(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
[[Page 49548]]
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 interval. 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] TR16AU12.003
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.
Sec. 60.5408 What is an optional procedure for measuring hydrogen
sulfide in acid gas--Tutwiler Procedure?
The Tutwiler procedure may be found in the 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)
[[Page 49549]]
(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
[GRAPHIC] [TIFF OMITTED] TR16AU12.004
[[Page 49550]]
BILLING CODE 6560-50-C
Sec. 60.5410 How do I demonstrate initial compliance with the
standards for my gas well affected facility, my centrifugal compressor
affected facility, my reciprocating compressor affected facility, my
pneumatic controller affected facility, my storage vessel affected
facility, and my equipment leaks and sweetening unit 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 October 15,
2012 or upon initial startup, whichever is later, and ends no later
than one year after the initial startup date for your affected facility
or no later than one year after October 15, 2012. The initial
compliance period may be less than one full year.
(a) To achieve initial compliance with the standards for each well
completion operation conducted at your gas well affected facility you
must comply with paragraphs (a)(1) through (a)(4) of this section.
(1) You must submit the notification required in Sec.
60.5420(a)(2).
(2) You must submit the initial annual report for your well
affected facility as required in Sec. 60.5420(b).
(3) You must maintain a log of records as specified in Sec.
60.5420(c)(1) for each well completion operation conducted during the
initial compliance period.
(4) For each gas well affected facility subject to both Sec.
60.5375(a)(1) and (3), you must maintain records of one or more digital
photographs with the date the photograph was taken and the latitude and
longitude of the well site imbedded within or stored with the digital
file showing the equipment for storing or re-injecting recovered
liquid, equipment for routing recovered gas to the gas flow line and
the completion combustion device (if applicable) connected to and
operating at each gas well completion operation that occurred during
the initial compliance period. As an alternative to imbedded latitude
and longitude within the digital photograph, the digital photograph may
consist of a photograph of the equipment connected and operating at
each well completion operation with a photograph of a separately
operating GIS device within the same digital picture, provided the
latitude and longitude output of the GIS unit can be clearly read in
the digital photograph.
(b)(1) To achieve initial compliance with standards for your
centrifugal compressor affected facility you must reduce VOC emissions
from each centrifugal compressor wet seal fluid degassing system by
95.0 percent or greater as required by Sec. 60.5380 and as
demonstrated by the requirements of Sec. 60.5413.
(2) If you use a control device to reduce emissions, you must equip
the wet seal fluid degassing system with a cover that meets the
requirements of Sec. 60.5411(b) and is connected through a closed vent
system that meets the requirements of Sec. 60.5411(a) to a control
device that meets the conditions specified in Sec. 60.5412.
(3) You must conduct an initial performance test as required in
Sec. 60.5413 within 180 days after initial startup or by October 15,
2012, whichever is later, and you must comply with the continuous
compliance requirements in Sec. 60.5415(b).
(4) You must conduct the initial inspections required in Sec.
60.5416.
(5) You must install and operate the continuous parameter
monitoring systems in accordance with Sec. 60.5417.
(6) You must submit the notifications required in 60.7(a)(1), (3),
and (4).
(7) You must submit the initial annual report for your centrifugal
compressor affected facility as required in Sec. 60.5420(b) for each
centrifugal compressor affected facility
(8) You must maintain the records as specified in Sec.
60.5420(c)(3).
(c) To achieve initial compliance with the standards for each
reciprocating compressor affected facility you must comply with
paragraphs (c)(1) through (4) of this section.
(1) During the initial compliance period, you must continuously
monitor the number of hours of operation or track the number of months
since the last rod packing replacement.
(2) You must submit the notifications required in 60.7(a)(1), (3),
and (4).
(3) You must submit the initial annual report for your
reciprocating compressor as required in Sec. 60.5420(b).
(4) You must maintain the records as specified in Sec.
60.5420(c)(3) for each reciprocating compressor affected facility.
(d) To achieve initial compliance with emission standards for your
pneumatic controller affected facility you comply with the requirements
specified in paragraphs (d)(1) through (6) of this section.
(1) If applicable, you have demonstrated by maintaining records as
specified in Sec. 60.5420(c)(4)(ii) of your determination that the use
of a pneumatic controller affected facility with a bleed rate greater
than 6 standard cubic feet of gas per hour is required as specified in
Sec. 60.5390(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
located between the wellhead and a natural gas processing plant and the
manufacturer's design specifications indicate that the controller emits
less than or equal to 6 standard cubic feet of gas per hour.
(4) You must tag each new pneumatic controller affected facility
according to the requirements of Sec. 60.5390(b)(2).
(5) You must include the information in paragraph (d)(1) of this
section and a listing of the pneumatic controller affected facilities
specified in paragraphs (d)(2) and (3) of this section in the initial
annual report submitted for your pneumatic controller affected
facilities constructed, modified or reconstructed during the period
covered by the annual report according to the requirements of Sec.
60.5420(b).
(6) You must maintain the records as specified in Sec.
60.5420(c)(4) for each pneumatic controller affected facility.
(e) To achieve initial compliance with the emission standards for
your storage vessel affected facility you must comply with paragraphs
(e)(1) through (9) of this section.
(1) You have determined the VOC emission rate within 30 days after
startup for storage vessels constructed, modified or reconstructed at
well sites with no other wells in production, and you must use good
engineering practices to minimize emissions during the 30-day period.
(2) You must determine the VOC emission rate upon startup for
storage vessels constructed, modified or reconstructed at well sites
with one or more wells already in production.
(3) For storage vessel affected facilities emitting more than 6 tpy
VOC, you must reduce VOC emissions by 95.0 percent or greater within 60
days after startup for storage vessels constructed, modified or
reconstructed at well sites with no other wells in production, or upon
startup for storage vessels constructed, modified or reconstructed at
well sites with one or more wells already in production.
(4) If you use a control device to reduce emissions, you must equip
the storage vessel with a cover that meets the requirements of Sec.
60.5411(b) and is connected through a closed vent system that meets the
requirements of Sec. 60.5411(a) to a control device that meets the
conditions specified in Sec. 60.5412 within 60 days after startup for
storage vessels constructed, modified
[[Page 49551]]
or reconstructed at well sites with no other wells in production, or
upon startup for storage vessels constructed, modified or reconstructed
at well sites with one or more wells already in production.
(5) You must conduct an initial performance test as required in
Sec. 60.5413 within 180 days after initial startup or within 180 days
of October 15, 2013, whichever is later, and must conduct the
compliance demonstration in Sec. 60.5415(b).
(6) You must conduct the initial inspections required in Sec.
60.5416.
(7) You must install and operate continuous parameter monitoring
systems in accordance with Sec. 60.5417.
(8) You must submit the information in paragraphs (e)(1) through
(7) of this section in the initial annual report as required in Sec.
60.5420(b).
(9) You must maintain the records as specified in Sec.
60.5420(c)(5) for each storage vessel affected facility.
(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 (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 (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 (2) of
this section in the initial annual report submitted for your sweetening
unit affected facilities at onshore natural gas processing plants.
Sec. 60.5411 What additional requirements must I meet to determine
initial compliance for my closed vent systems routing materials from
storage vessels and centrifugal compressor wet seal degassing systems?
You must meet the applicable requirements of this section for each
cover and closed vent system used to comply with the emission standards
for your storage vessel or centrifugal compressor affected facility.
(a) Closed vent system requirements. (1) You must design the closed
vent system to route all gases, vapors, and fumes emitted from the
material in the storage vessel or wet seal fluid degassing system to a
control device that meets the requirements specified in Sec. 60.5412.
(2) You must design and operate the closed vent system with no
detectable emissions as demonstrated by Sec. 60.5416(b).
(3) You must meet the requirements specified in paragraphs
(a)(3)(i) and (ii) of this section if the closed vent system contains
one or more bypass devices that could be used to divert all or a
portion of the gases, vapors, or fumes from entering the control
device.
(i) Except as provided in paragraph (a)(3)(ii) of this section, you
must comply with either paragraph (a)(3)(i)(A) or (B) of this section
for each bypass device.
(A) You must properly install, calibrate, maintain, and operate a
flow indicator at the inlet to the bypass device that could divert the
stream away from the control device to the atmosphere that is capable
of taking periodic readings as specified in Sec. 60.5416(a)(4) and
sounds an alarm when the bypass device is open such that the stream is
being, or could be, diverted away from the control device to the
atmosphere.
(B) You must secure the bypass device valve installed at the inlet
to the bypass device in the non-diverting position using a car-seal or
a lock-and-key type configuration.
(ii) Low leg drains, high point bleeds, analyzer vents, open-ended
valves or lines, and safety devices are not subject to the requirements
of paragraph (a)(3)(i) of this section.
(b) Cover requirements. (1) The cover and all openings on the cover
(e.g., access hatches, sampling ports, and gauge wells) shall form a
continuous barrier over the entire surface area of the liquid in the
storage vessel or wet seal fluid degassing system.
(2) Each cover opening shall be secured in a closed, sealed
position (e.g., covered by a gasketed lid or cap) whenever material is
in the unit on which the cover is installed except during those times
when it is necessary to use an opening as follows:
(i) To add material to, or remove material from the unit (this
includes openings necessary to equalize or balance the internal
pressure of the unit following changes in the level of the material in
the unit);
(ii) To inspect or sample the material in the unit;
(iii) To inspect, maintain, repair, or replace equipment located
inside the unit; or
(iv) To vent liquids, gases, or fumes from the unit through a
closed-vent system to a control device designed and operated in
accordance with the requirements of paragraph (a) of this section.
Sec. 60.5412 What additional requirements must I meet for determining
initial compliance with control devices used to comply with the
emission standards for my storage vessel or centrifugal compressor
affected facility?
You must meet the applicable requirements of this section for each
control device used to comply with the emission standards for your
storage vessel or centrifugal compressor affected facility.
(a) If you use a control device to meet the emission reduction
standard in Sec. 60.5380(a)(1) for your centrifugal compressor or
Sec. 60.5395(a)(1) or (2) for your storage vessel, you must use one of
the control devices specified in paragraphs (a)(1) through (3) of this
section. You must demonstrate that the control device achieves the
performance requirements using the performance test methods and
procedures specified in Sec. 60.5413.
(1) You must design and operate an enclosed combustion device
(e.g., thermal vapor incinerator, catalytic vapor incinerator, boiler,
or process heater) in accordance with one of the performance
requirements specified in paragraphs (a)(1)(i) through (iv) of this
section.
(i) You must reduce the mass content of VOC in the gases vented to
the device by 95.0 percent by weight or greater as determined in
accordance with the requirements of Sec. 60.5413.
(ii) You must reduce the concentration of TOC in the exhaust gases
at the outlet to the device to a level equal to or less than 20 parts
per million by volume on a dry basis corrected to 3 percent oxygen as
determined in accordance with the requirements of Sec. 60.5413.
(iii) You must operate at a minimum temperature of 760 [deg]C for a
control device that can demonstrate a uniform combustion zone
temperature during the performance test conducted under Sec. 60.5413.
(iv) If a boiler or process heater is used as the control device,
then you must introduce the vent stream into the flame zone of the
boiler or process heater.
[[Page 49552]]
(2) You must design and operate a vapor recovery device (e.g.,
carbon adsorption system or condenser) or other non-destructive control
device to reduce the mass content of VOC in the gases vented to the
device by 95.0 percent by weight or greater as determined in accordance
with the requirements of Sec. 60.5413. The vapor recovery device must
meet the design analysis requirements of Sec. 60.5413(c).
(3) You must design and operate a flare in accordance with the
requirements of Sec. 60.5413.
(b) You must operate each control device in accordance with the
requirements specified in paragraphs (b)(1) and (2) of this section.
(1) You must operate each control device used to comply with this
subpart at all times when gases, vapors, and fumes are vented from the
storage vessel affected facility, as required under Sec. 60.5395, or
wet seal fluid degassing system affected facility, as required under
Sec. 60.5380, through the closed vent system to the control device.
You may vent more than one affected facility to a control device used
to comply with this subpart.
(2) For each control device monitored in accordance with the
requirements of Sec. 60.5417, you must demonstrate compliance
according to the requirements of Sec. 60.5415(e)(2), as applicable.
(c) For each carbon adsorption system used as a control device to
meet the requirements of paragraph (a)(2) of this section, you must
manage the carbon in accordance with the requirements specified in
paragraphs (c)(1) or (2) of this section.
(1) Following the initial startup of the control device, you must
replace all carbon in the control device with fresh carbon on a
regular, predetermined time interval that is no longer than the carbon
service life established according to Sec. 60.5413(c)(2) or (3) for
the carbon adsorption system. You must maintain records identifying the
schedule for replacement and records of each carbon replacement as
required in Sec. 60.5420(c)(6).
(2) You must either regenerate, reactivate, or burn the spent
carbon removed from the carbon adsorption system in one of the units
specified in paragraphs (c)(2)(i) through (vii) of this section.
(i) Regenerate or reactivate the spent carbon in a thermal
treatment unit for which you have been issued a final permit under 40
CFR part 270 that implements the requirements of 40 CFR part 264,
subpart X.
(ii) Regenerate or reactivate the spent carbon in a thermal
treatment unit equipped with and operating air emission controls in
accordance with this section.
(iii) Regenerate or reactivate the spent carbon in a thermal
treatment unit equipped with and operating organic air emission
controls in accordance with an emissions standard for VOC under another
subpart in 40 CFR part 60 or this part.
(iv) Burn the spent carbon in a hazardous waste incinerator for
which the owner or operator has been issued a final permit under 40 CFR
part 270 that implements the requirements of 40 CFR part 264, subpart
O.
(v) Burn the spent carbon in a hazardous waste incinerator which
you have designed and operated in accordance with the requirements of
40 CFR part 265, subpart O.
(vi) Burn the spent carbon in a boiler or industrial furnace for
which you have been issued a final permit under 40 CFR part 270 that
implements the requirements of 40 CFR part 266, subpart H.
(vii) Burn the spent carbon in a boiler or industrial furnace that
you have designed and operated in accordance with the interim status
requirements of 40 CFR part 266, subpart H.
Sec. 60.5413 What are the performance testing procedures for control
devices used to demonstrate compliance at my storage vessel or
centrifugal compressor affected facility?
This section applies to the performance testing of control devices
used to demonstrate compliance with the emissions standards for your
storage vessel or centrifugal compressor affected facility. You must
demonstrate that a control device achieves the performance requirements
of Sec. 60.5412(a) using the performance test methods and procedures
specified in paragraph (b) of this section. For condensers, you may use
a design analysis as specified in paragraph (c) of this section in lieu
of complying with paragraph (b) of this section.
(a) Performance test exemptions. You are exempt from the
requirements to conduct performance tests and design analyses if you
use any of the control devices described in paragraphs (a)(1) through
(7) of this section.
(1) A flare that is designed and operated in accordance with Sec.
60.18(b). You must conduct the compliance determination using Method 22
at 40 CFR part 60, appendix A-7, to determine visible emissions.
(2) A boiler or process heater with a design heat input capacity of
44 megawatts or greater.
(3) A boiler or process heater into which the vent stream is
introduced with the primary fuel or is used as the primary fuel.
(4) A boiler or process heater burning hazardous waste for which
you have either been issued a final permit under 40 CFR part 270 and
comply with the requirements of 40 CFR part 266, subpart H; or you have
certified compliance with the interim status requirements of 40 CFR
part 266, subpart H.
(5) A hazardous waste incinerator for which you have been issued a
final permit under 40 CFR part 270 and comply with the requirements of
40 CFR part 264, subpart O; or you have certified compliance with the
interim status requirements of 40 CFR part 265, subpart O.
(6) A performance test is waived in accordance with Sec. 60.8(b).
(7) A control device that can be demonstrated to meet the
performance requirements of Sec. 60.5412(a) through a performance test
conducted by the manufacturer, as specified in paragraph (d) of this
section.
(b) Test methods and procedures. You must use the test methods and
procedures specified in paragraphs (b)(1) through (5) of this section,
as applicable, for each performance test conducted to demonstrate that
a control device meets the requirements of Sec. 60.5412(a). You must
conduct the initial and periodic performance tests according to the
schedule specified in paragraph (b)(5) of this section.
(1) You must use Method 1 or 1A at 40 CFR part 60, appendix A-1, as
appropriate, to select the sampling sites specified in paragraphs
(b)(1)(i) and (ii) of this section. Any references to particulate
mentioned in Methods 1 and 1A do not apply to this section.
(i) Sampling sites must be located at the inlet of the first
control device, and at the outlet of the final control device, to
determine compliance with the control device percent reduction
requirement specified in Sec. 60.5412(a)(1)(i) or (a)(2).
(ii) The sampling site must be located at the outlet of the
combustion device to determine compliance with the enclosed combustion
device total TOC concentration limit specified in Sec.
60.5412(a)(1)(ii).
(2) You must determine the gas volumetric flowrate using Method 2,
2A, 2C, or 2D at 40 CFR part 60, appendix A-2, as appropriate.
(3) To determine compliance with the control device percent
reduction performance requirement in Sec. 60.5412(a)(1)(i) or (a)(2),
you must use Method 25A at 40 CFR part 60, appendix A-7. You must use
the procedures in paragraphs (b)(3)(i)
[[Page 49553]]
through (iv) of this section to calculate percent reduction efficiency.
(i) For each run, you must take either an integrated sample or a
minimum of four grab samples per hour. If grab sampling is used, then
the samples must be taken at approximately equal intervals in time,
such as 15-minute intervals during the run.
(ii) You must compute the mass rate of TOC (minus methane and
ethane) using the equations and procedures specified in paragraphs
(b)(3)(ii)(A) and (B) of this section.
(A) You must use the following equations:
[GRAPHIC] [TIFF OMITTED] TR16AU12.005
Where:
Ei, Eo = Mass rate of TOC (minus methane and
ethane) at the inlet and outlet of the control device, respectively,
dry basis, kilogram per hour.
K2 = Constant, 2.494 x 10-6 (parts per
million) (gram-mole per standard cubic meter) (kilogram/gram)
(minute/hour), where standard temperature (gram-mole per standard
cubic meter) is 20 [deg]C.
Cij, Coj = Concentration of sample component j
of the gas stream at the inlet and outlet of the control device,
respectively, dry basis, parts per million by volume.
Mij, Moj = Molecular weight of sample
component j of the gas stream at the inlet and outlet of the control
device, respectively, gram/gram-mole.
Qi, Qo = Flowrate of gas stream at the inlet
and outlet of the control device, respectively, dry standard cubic
meter per minute.
n = Number of components in sample.
(B) When calculating the TOC mass rate, you must sum all organic
compounds (minus methane and ethane) measured by Method 25A at 40 CFR
part 60, appendix A-7 using the equations in paragraph (b)(3)(ii)(A) of
this section.
(iii) You must calculate the percent reduction in TOC (minus
methane and ethane) as follows:
[GRAPHIC] [TIFF OMITTED] TR16AU12.006
Where:
Rcd = Control efficiency of control device, percent.
Ei = Mass rate of TOC (minus methane and ethane) at the
inlet to the control device as calculated under paragraph (b)(3)(ii)
of this section, kilograms TOC per hour or kilograms HAP per hour.
Eo = Mass rate of TOC (minus methane and ethane) at the
outlet of the control device, as calculated under paragraph
(b)(3)(ii) of this section, kilograms TOC per hour per hour.
(iv) If the vent stream entering a boiler or process heater with a
design capacity less than 44 megawatts is introduced with the
combustion air or as a secondary fuel, you must determine the weight-
percent reduction of total TOC (minus methane and ethane) across the
device by comparing the TOC (minus methane and ethane) in all combusted
vent streams and primary and secondary fuels with the TOC (minus
methane and ethane) exiting the device, respectively.
(4) You must use Method 25A at 40 CFR part 60, appendix A-7 to
measure TOC (minus methane and ethane) to determine compliance with the
enclosed combustion device total VOC concentration limit specified in
Sec. 60.5412(a)(1)(ii). You must calculate parts per million by volume
concentration and correct to 3 percent oxygen, using the procedures in
paragraphs (b)(4)(i) through (iii) of this section.
(i) For each run, you must take either an integrated sample or a
minimum of four grab samples per hour. If grab sampling is used, then
the samples must be taken at approximately equal intervals in time,
such as 15-minute intervals during the run.
(ii) You must calculate the TOC concentration for each run as
follows:
[GRAPHIC] [TIFF OMITTED] TR16AU12.007
Where:
CTOC = Concentration of total organic compounds minus
methane and ethane, dry basis, parts per million by volume.
Cji = Concentration of sample component j of sample i,
dry basis, parts per million by volume.
n = Number of components in the sample.
x = Number of samples in the sample run.
(iii) You must correct the TOC concentration to 3 percent oxygen as
specified in paragraphs (b)(4)(iii)(A) and (B) of this section.
(A) You must use the emission rate correction factor for excess
air, integrated sampling and analysis procedures of Method 3A or 3B at
40 CFR part 60, appendix A, ASTM D6522-00 (Reapproved 2005), or ANSI/
ASME PTC 19.10-1981, Part 10 (manual portion only) (incorporated by
reference as specified in Sec. 60.17) to determine the oxygen
concentration. The samples must be taken during the same time that the
samples are taken for determining TOC concentration.
(B) You must correct the TOC concentration for percent oxygen as
follows:
[GRAPHIC] [TIFF OMITTED] TR16AU12.008
Where:
Cc = TOC concentration corrected to 3 percent oxygen, dry
basis, parts per million by volume.
Cm = TOC concentration, dry basis, parts per million by
volume.
%O2d = Concentration of oxygen, dry basis, percent by
volume.
(5) You must conduct performance tests according to the schedule
specified in paragraphs (b)(5)(i) and (ii) of this section.
(i) You must conduct an initial performance test within 180 days
after initial startup for your affected facility. You must submit the
performance test results as required in Sec. 60.5420(b)(7).
(ii) You must conduct periodic performance tests for all control
devices required to conduct initial performance tests except as
specified in paragraphs (b)(5)(ii)(A) and (B) of this section. You must
conduct the first periodic performance test no later than 60 months
after the initial performance test required in paragraph (b)(5)(i) of
this section. You must conduct subsequent periodic performance tests at
intervals no longer than 60 months following the previous periodic
performance test or whenever you desire to establish a new operating
limit. You must submit the periodic performance test results as
specified in Sec. 60.5420(b)(7). Combustion control devices meeting
the criteria in either paragraph (b)(5)(ii)(A) or (B) of this section
are not required to conduct periodic performance tests.
(A) A control device whose model is tested under, and meets the
criteria of paragraph (d) of this section.
(B) A combustion control device tested under paragraph (b) of this
section that meets the outlet TOC performance level specified in Sec.
60.5412(a)(1)(ii) and that establishes a correlation between firebox or
combustion chamber temperature and the TOC performance level.
(c) Control device design analysis to meet the requirements of
Sec. 60.5412(a). (1) For a condenser, the design analysis must include
an analysis of the vent stream composition, constituent concentrations,
flowrate, relative humidity, and temperature, and must establish the
design outlet organic compound concentration level, design average
temperature of the condenser exhaust vent stream, and the design
[[Page 49554]]
average temperatures of the coolant fluid at the condenser inlet and
outlet.
(2) For a regenerable carbon adsorption system, the design analysis
shall include the vent stream composition, constituent concentrations,
flowrate, relative humidity, and temperature, and shall establish the
design exhaust vent stream organic compound concentration level,
adsorption cycle time, number and capacity of carbon beds, type and
working capacity of activated carbon used for the carbon beds, design
total regeneration stream flow over the period of each complete carbon
bed regeneration cycle, design carbon bed temperature after
regeneration, design carbon bed regeneration time, and design service
life of the carbon.
(3) For a nonregenerable carbon adsorption system, such as a carbon
canister, the design analysis shall include the vent stream
composition, constituent concentrations, flowrate, relative humidity,
and temperature, and shall establish the design exhaust vent stream
organic compound concentration level, capacity of the carbon bed, type
and working capacity of activated carbon used for the carbon bed, and
design carbon replacement interval based on the total carbon working
capacity of the control device and source operating schedule. In
addition, these systems will incorporate dual carbon canisters in case
of emission breakthrough occurring in one canister.
(4) If you and the Administrator do not agree on a demonstration of
control device performance using a design analysis, then you must
perform a performance test in accordance with the requirements of
paragraph (b) of this section to resolve the disagreement. The
Administrator may choose to have an authorized representative observe
the performance test.
(d) Performance testing for combustion control devices--
manufacturers' performance test. The manufacturer must demonstrate that
a specific model of combustion control device achieves the performance
requirements in paragraph (d)(1) of this section by conducting a
performance test as specified in paragraphs (d)(2) through (8) of this
section. You must submit a test report for each combustion control
device in accordance with the requirements in paragraphs (d)(9) of this
section.
(1) The manufacturer must meet the performance test criteria in
paragraphs (d)(1)(i) through (iii) of this section.
(i) The control device model tested must meet the emission levels
in paragraphs (d)(1)(i)(A) through (C) of this section.
(A) Method 22 at 40 CFR part 60, appendix A-7, results under
paragraph (d)(6)(iv) of this section with no indication of visible
emissions.
(B) Average Method 25A at 40 CFR part 60, appendix A-7, results
under paragraph (d)(8) of this section equal to or less than 10.0 parts
per million by volume-wet THC as propane corrected to 3.0 percent
carbon dioxide, and
(C) Average carbon monoxide emissions determined under paragraph
(d)(6)(iii) of this section equal to or less than 10 parts per million
by volume-dry, corrected to 3.0 percent carbon dioxide.
(ii) The manufacturer must determine a maximum inlet gas flow rate,
which must not be exceeded for each control device model to achieve the
criteria in paragraph (d)(1)(i) of this section.
(iii) A control device meeting the emission levels in paragraph
(d)(1)(i)(A) through (C) of this section must demonstrate a minimum
destruction efficiency of 95.0 percent for VOC regulated under this
subpart.
(2) Performance testing must consist of three one-hour (or longer)
test runs for each of the four firing rate settings in paragraphs
(d)(2)(i) through (iv) of this section, making a total of 12 test runs
per test. The manufacturer must use propene (propylene) gas for the
testing fuel. An independent third-party laboratory (not affiliated
with the control device manufacturer or fuel supplier) must perform all
fuel analyses.
(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 up
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 up
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 up
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) The manufacturer must test all models employing multiple
enclosures simultaneously and with all burners operational. The
manufacturer must report results for each enclosure individually and
for the average of the emissions from all interconnected combustion
enclosures/chambers. Control device operating data must be collected
continuously throughout the performance test using an electronic Data
Acquisition System and strip chart. The manufacturer must submit data
with the test report in accordance with paragraph (d)(9) of this
section.
(4) The manufacturer must conduct inlet testing as specified in
paragraphs (d)(4)(i) through (iii) of this section.
(i) The fuel flow metering system must be located in accordance
with Method 2A at 40 CFR part 60, appendix A-1, (or other approved
procedure) to measure fuel flow rate at the control device inlet
location. You must position the fitting for filling fuel sample
containers a minimum of eight pipe diameters upstream of any inlet fuel
flow monitoring meter.
(ii) The manufacturer must determine the inlet flow rate using
Method 2A at 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) The manufacturer must conduct inlet fuel sampling in
accordance with the criteria in paragraph (d)(5) of this section.
(5) The manufacturer must conduct inlet fuel sampling as specified
in paragraphs (d)(5)(i) and (ii) of this section.
(i) At the inlet fuel sampling location, the manufacturer must
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 must be conducted as specified in paragraphs
(d)(5)(i)(A) through (C) of this section.
(A) Open the canister sampling valve at the beginning of the total
hydrocarbon test, and close the canister at the end of the total
hydrocarbon test.
(B) Fill one canister for each total hydrocarbon test run.
(C) Label the canisters individually and record on a chain of
custody form.
(ii) The manufacturer must analyze each fuel sample using the
methods in paragraphs (d)(5)(ii)(A) through (D) of this section. You
must include the results in the test report in paragraph (d)(9) of this
section.
[[Page 49555]]
(A) Hydrocarbon compounds containing between one and five atoms of
carbon plus benzene using ASTM D1945-03 (Reapproved 2010) (incorporated
by reference as specified in Sec. 60.17).
(B) Hydrogen (H2), carbon monoxide (CO), carbon dioxide
(CO2), nitrogen (N2), oxygen (O2)
using ASTM D1945-03 (Reapproved 2010) (incorporated by reference as
specified in Sec. 60.17).
(C) Carbonyl sulfide, carbon disulfide plus mercaptans using ASTM
D5504-08 (incorporated by reference as specified in Sec. 60.17).
(D) Higher heating value using ASTM D3588-98 (Reapproved 2003) or
ASTM D4891-89 (Reapproved 2006) (incorporated by reference as specified
in Sec. 60.17).
(6) The manufacturer must conduct outlet testing in accordance with
the criteria in paragraphs (d)(6)(i) through (iv) and (d)(7) of this
section.
(i) The manufacturer must sample and measure flowrate in accordance
with the following:
(A) The manufacturer must position the outlet sampling location a
minimum of four 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 must be used.
(B) The manufacturer must measure flow rate using Method 1 at 40
CFR part 60, appendix A-1 for determining flow measurement traverse
point location, and Method 2 at 40 CFR part 60, appendix A-1 for
measuring 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 must be used to obtain
an accurate flow profile.
(ii) The manufacturer must determine molecular weight as specified
in paragraph (d)(7) of this section.
(iii) The manufacturer must determine carbon monoxide using Method
10 at 40 CFR part 60, appendix A-4 or ASTM D6522-00 (Reapproved 2005)
(incorporated by reference as specified in Sec. 60.17). The
manufacturer must run the test at the same time and with the sample
points used for the Method 25A at 40 CFR part 60, appendix A-7,
testing. An instrument range of 0-10 parts per million by volume-dry
(ppmvd) must be used.
(iv) The manufacturer must determine visible emissions using Method
22 at 40 CFR part 60, appendix A-7. The test must 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.
(7) The manufacturer must determine molecular weight as specified
in paragraphs (d)(7)(i) and (ii) of this section.
(i) The manufacturer must collect an integrated bag sample during
the Method 4 at 40 CFR part 60, appendix A-3, moisture test. The
manufacturer must analyze the bag sample using a gas chromatograph-
thermal conductivity detector (GC-TCD) analysis meeting the criteria in
paragraphs (d)(7)(i)(A) through (D) of this section.
(A) Collect the integrated sample throughout the entire test, and
collect representative volumes from each traverse location.
(B) Purge the sampling line with stack gas before opening the valve
and beginning to fill the bag.
(C) Knead or otherwise vigorously mix the bag contents prior to the
gas chromatograph analysis.
(D) Modify the gas chromatograph-thermal conductivity detector
calibration procedure in Method 3C at 40 CFR part 60, appendix A-2 by
using EPA Alt-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, repeat the initial calibration using at least three
concentration levels.
(ii) The manufacturer must report the molecular weight of oxygen,
carbon dioxide, methane, and nitrogen and include in the test report
submitted under Sec. 60.5420(b)(7). The manufacturer must determine
moisture using Method 4 at 40 CFR part 60, appendix A-3. Traverse both
ports with the Method 4 at 40 CFR part 60, appendix A-3, sampling train
during each test run. The manufacturer must not introduce ambient air
into the Method 3C at 40 CFR part 60, appendix A-2, integrated bag
sample during the port change.
(8) The manufacturer must determine total hydrocarbons as specified
by the criteria in paragraphs (d)(8)(i) through (vii) of this section.
(i) Conduct THC sampling using Method 25A at 40 CFR part 60,
appendix A-7, except the option for locating the probe in the center 10
percent of the stack is not 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 must consist of three Method 25A at 40 CFR part
60, appendix A-7, 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.
(v) THC measurements must be reported in terms of ppmvw as propane.
(vi) THC results must be corrected to 3 percent CO2, as
measured by Method 3C at 40 CFR part 60, appendix A-2.
(vii) Subtraction of methane/ethane from the THC data is not
allowed in determining results.
(9) For each combustion control device model tested by the
manufacturer under this section, you must maintain records of the
information listed in paragraphs (d)(9)(i) through (vi) of this
section.
(i) A full schematic of the control device and dimensions of the
device components.
(ii) The design net heating value (minimum and maximum) of the
device.
(iii) The test fuel gas flow range (in both mass and volume).
Include the minimum and maximum allowable inlet gas flow rate.
(iv) The air/stream injection/assist ranges, if used.
(v) The test parameter ranges listed in paragraphs (d)(9)(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) You must include all calibration quality assurance/quality
control data, calibration gas values, gas cylinder certification, and
strip charts annotated
[[Page 49556]]
with test times and calibration values in the test report.
Sec. 60.5415 How do I demonstrate continuous compliance with the
standards for my gas well 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 well affected facility, you must demonstrate
continuous compliance by submitting the reports required by Sec.
60.5420(b) and maintaining the records for each completion operation
specified in Sec. 60.5420(c)(1).
(b) For each centrifugal compressor affected facility, you must
demonstrate continuous compliance according to paragraphs (b)(1) and
(2) of this section.
(1) You must reduce VOC emissions from the wet seal fluid degassing
system by 95.0 percent or greater.
(2) If you use a control device to reduce emissions, you must
demonstrate continuous compliance according to paragraph (e)(2) of this
section.
(3) You must submit the annual report required by 60.5420(b) and
maintain the records as specified in Sec. 60.5420(c)(2).
(c) For each reciprocating compressor affected facility, you must
demonstrate continuous compliance according to paragraphs (c)(1)
through (3) of this section.
(1) You must continuously monitor the number of hours of operation
for each reciprocating compressor affected facility or track the number
of months since initial startup, or October 15, 2012, or the date of
the most recent reciprocating compressor rod packing replacement,
whichever is later.
(2) You must submit the annual report as required in Sec.
60.5420(b) and maintain records as required in Sec. 60.5420(c)(3).
(3) You must replace the reciprocating compressor rod packing
before the total number of hours of operation reaches 26,000 hours or
the number of months since the most recent rod packing replacement
reaches 36 months.
(d) For each pneumatic controller affected facility, you must
demonstrate continuous compliance according to paragraphs (d)(1)
through (3) of this section.
(1) You must continuously operate the pneumatic controllers as
required in Sec. 60.5390(a), (b), or (c).
(2) You must submit the annual report as required in Sec.
60.5420(b).
(3) You must maintain records as required in Sec. 60.5420(c)(4).
(e) For each storage vessel affected facility for which the VOC
emissions are greater than 6 tpy, you must demonstrate continuous
compliance according to paragraphs (e)(1) and (2) of this section.
(1) You must reduce VOC emissions from each storage vessel are
reduced by 95.0 percent or greater.
(2) If you use a control device to reduce VOC emissions, you must
demonstrate continuous compliance with the performance requirements of
Sec. 60.5412(a)(2) using the procedure specified in paragraphs
(e)(2)(i) through (vii) of this section. If you use a condenser as the
control device to achieve the requirements specified in Sec.
60.5412(a)(2), you may demonstrate compliance according to paragraph
(e)(2)(viii) of this section. You may switch between compliance with
paragraphs (e)(2)(i) through (vii) of this section and compliance with
paragraph (e)(2)(viii) of this section only after at least 1 year of
operation in compliance with the selected approach. You must provide
notification of such a change in the compliance method in the next
Annual Report, as required in Sec. 60.5420(b), following the change.
(i) You must operate below (or above) the site specific maximum (or
minimum) parameter value established according to the requirements of
Sec. 60.5417(f)(1).
(ii) You must calculate the daily average of the applicable
monitored parameter in accordance with Sec. 60.5417(e) except that the
inlet gas flow rate to the control device must not be averaged.
(iii) Compliance with the operating parameter limit is achieved
when the daily average of the monitoring parameter value calculated
under paragraph (e)(2)(ii) of this section is either equal to or
greater than the minimum monitoring value or equal to or less than the
maximum monitoring value established under paragraph (e)(2)(i) of this
section. When performance testing of a combustion control device is
conducted by the device manufacturer as specified in Sec. 60.5413(d),
compliance with the operating parameter limit is achieved when the
inlet gas flow rate is equal to or less than the value established
under Sec. 60.5413(d)(1)(ii).
(iv) You must operate the continuous monitoring system required in
Sec. 60.5417 at all times the affected source is operating, 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). 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. You are required to
complete monitoring system repairs in response to monitoring system
malfunctions and to return the monitoring system to operation as
expeditiously as practicable.
(v) You may not use data recorded during monitoring system
malfunctions, repairs associated with monitoring system malfunctions,
or required monitoring system quality assurance or control activities
in calculations used to report emissions or operating levels. You must
use all the data collected during all other required data collection
periods to assess the operation of the control device and associated
control system.
(vi) Failure to collect required data is a deviation of the
monitoring requirements, 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).
(vii) If you use a combustion control device to meet the
requirements of Sec. 60.5412(a), you must demonstrate compliance by
installing a device tested under the provisions in Sec. 60.5413(d) and
complying with the criteria in paragraphs (e)(2)(vii)(A) through (D) of
this section.
(A) The inlet gas flow rate must meet the range specified by the
manufacturer. You must measure the flow rate as specified in Sec.
60.5417(d)(1)(viii)(A).
(B) A pilot flame must be present at all times of operation. You
must monitor the pilot flame in accordance with Sec.
60.5417(d)(1)(viii)(B).
(C) You must operate the combustion control device with no visible
emissions, except for periods not to exceed a total of 5 minutes during
any 2 consecutive hours. You must perform a visible emissions test
using Method 22 at 40 CFR part 60, appendix A-7 monthly. The
observation period must be 2 hours and must follow Method 22.
(D) Compliance with the operating parameter limit is achieved when
the criteria in paragraphs (e)(2)(vii)(D)(1) through (5) are met.
(1) The inlet gas flow rate monitored under paragraph
(e)(2)(vii)(A) of this section is equal to or below the maximum
established by the manufacturer.
[[Page 49557]]
(2) The pilot flame is present at all times; and
(3) During the visible emissions test performed under paragraph
(e)(2)(vii)(C) 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 must follow the requirements in
paragraphs (e)(2)(vii)(D)(4) and (5) of this section.
(4) Following the first failure, you must replace the fuel
nozzle(s) and burner tubes.
(5) If, following replacement of the fuel nozzle(s) and burner
tubes as specified in paragraph (e)(2)(vii)(D)(4) of this section, the
visible emissions test is not passed in the next scheduled test, you
must either conduct a performance test as specified in Sec. 60.5413,
or replace the device with another control device whose model was
tested and meets the requirements in Sec. 60.5413(d).
(viii) If you use a condenser as the control device to achieve the
percent reduction performance requirements specified in Sec.
60.5412(a)(2), you must demonstrate compliance using the procedures in
paragraphs (e)(2)(viii)(A) through (E) of this section.
(A) You must establish a site-specific condenser performance curve
according to Sec. 60.5417(f)(2).
(B) You must calculate the daily average condenser outlet
temperature in accordance with Sec. 60.5417(e).
(C) You must determine the condenser efficiency for the current
operating day using the daily average condenser outlet temperature
calculated under paragraph (e)(2)(viii)(B) of this section and the
condenser performance curve established under paragraph (e)(2)(viii)(A)
of this section.
(D) Except as provided in paragraphs (e)(2)(viii)(D)(1) and (2) of
this section, at the end of each operating day, you must calculate the
365-day rolling average TOC emission reduction, as appropriate, from
the condenser efficiencies as determined in paragraph (e)(2)(viii)(C)
of this section.
(1) After the compliance dates specified in Sec. 60.5370, if you
have less than 120 days of data for determining average TOC emission
reduction, you must calculate the average TOC emission reduction for
the first 120 days of operation after the compliance dates. You have
demonstrated compliance with the overall 95.0 percent reduction
requirement if the 120-day average TOC emission reduction is equal to
or greater than 95.0 percent.
(2) After 120 days and no more than 364 days of operation after the
compliance date specified in Sec. 60.5370, you must calculate the
average TOC emission reduction as the TOC emission reduction averaged
over the number of days between the current day and the applicable
compliance date. You have demonstrated compliance with the overall 95.0
percent reduction requirement, if the average TOC emission reduction is
equal to or greater than 95.0 percent.
(E) If you have data for 365 days or more of operation, you have
demonstrated compliance with the TOC emission reduction if the rolling
365-day average TOC emission reduction calculated in paragraph
(e)(2)(viii)(D) of this section is equal to or greater than 95.0
percent.
(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 Sec. 60.5405(b)
according to paragraphs (g)(1) and (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 violations of emission standards 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 violations 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 standard, you must timely meet the reporting requirements in
Sec. 60.5420(a), and must prove by a preponderance of evidence that:
(i) The violation:
(A) Was caused by a sudden, infrequent, and unavoidable failure of
air pollution control 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) Was not part of a recurring pattern indicative of inadequate
design, operation, or maintenance; and
(ii) Repairs were made as expeditiously as possible when a
violation occurred. Off-shift and overtime labor were used, to the
extent practicable to make these repairs; and
(iii) The frequency, amount and duration of the violation
(including any bypass) were minimized to the maximum extent
practicable; and
(iv) If the violation 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
violation 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 violation 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, the purpose
of which is to determine, correct, and eliminate the primary causes of
the malfunction and the violation resulting from the malfunction event
at issue. The analysis shall also specify, using best monitoring
methods and engineering judgment, the amount of any emissions that were
the result of the malfunction.
(2) Report. The owner or operator seeking to assert an affirmative
defense shall submit a written report to the Administrator with all
necessary supporting documentation, that it has met the requirements
set forth in paragraph (h)(1) of this section. This affirmative defense
report shall be included in the first periodic compliance, deviation
report or excess emission report otherwise required after the initial
occurrence of the violation of the relevant standard (which may be the
end of any applicable averaging period). If such compliance, deviation
report or
[[Page 49558]]
excess emission report is due less than 45 days after the initial
occurrence of the violation, the affirmative defense report may be
included in the second compliance, deviation report or excess emission
report due after the initial occurrence of the violation of the
relevant standard.
Sec. 60.5416 What are the initial and continuous cover and closed
vent system inspection and monitoring requirements for my storage
vessel and centrifugal compressor affected facility?
For each closed vent system or cover at your storage vessel or
centrifugal compressor affected facility, you must comply with the
requirements of paragraphs (a) through (g) of this section.
(a) Inspections. Except as provided in paragraphs (e) and (f) of
this section, you must inspect each closed vent system according to the
procedures and schedule specified in paragraphs (a)(1) and (2) of this
section, inspect each cover according to the procedures and schedule
specified in paragraph (a)(3) of this section, and inspect each bypass
device according to the procedures of paragraph (a)(4) of this section.
(1) For each closed vent system joint, seam, or other connection
that is permanently or semi-permanently sealed (e.g., a welded joint
between two sections of hard piping or a bolted and gasketed ducting
flange), you must meet the requirements specified in paragraphs
(a)(1)(i) and (ii) of this section.
(i) Conduct an initial inspection according to the test methods and
procedures specified in paragraph (b) of this section to demonstrate
that the closed vent system operates with no detectable emissions. You
must maintain records of the inspection results as specified in Sec.
60.5420(c)(6).
(ii) Conduct annual visual inspections for defects that could
result in air emissions. Defects include, but are not limited to,
visible cracks, holes, or gaps in piping; loose connections; or broken
or missing caps or other closure devices. You must monitor a component
or connection using the test methods and procedures in paragraph (b) of
this section to demonstrate that it operates with no detectable
emissions following any time the component is repaired or replaced or
the connection is unsealed. You must maintain records of the inspection
results as specified in Sec. 60.5420(c)(6).
(2) For closed vent system components other than those specified in
paragraph (a)(1) of this section, you must meet the requirements of
paragraphs (a)(2)(i) through (iii) of this section.
(i) Conduct an initial inspection according to the test methods and
procedures specified in paragraph (b) of this section to demonstrate
that the closed vent system operates with no detectable emissions. You
must maintain records of the inspection results as specified in Sec.
60.5420(c)(6).
(ii) Conduct annual inspections according to the test methods and
procedures specified in paragraph (b) of this section to demonstrate
that the components or connections operate with no detectable
emissions. You must maintain records of the inspection results as
specified in Sec. 60.5420(c)(6).
(iii) Conduct annual visual inspections for defects that could
result in air emissions. Defects include, but are not limited to,
visible cracks, holes, or gaps in ductwork; loose connections; or
broken or missing caps or other closure devices. You must maintain
records of the inspection results as specified in Sec. 60.5420(c)(6).
(3) For each cover, you must meet the requirements in paragraphs
(a)(3)(i) and (ii) of this section.
(i) Conduct visual inspections for defects that could result in air
emissions. Defects include, but are not limited to, visible cracks,
holes, or gaps in the cover, or between the cover and the separator
wall; broken, cracked, or otherwise damaged seals or gaskets on closure
devices; and broken or missing hatches, access covers, caps, or other
closure devices. In the case where the storage vessel is buried
partially or entirely underground, you must inspect only those portions
of the cover that extend to or above the ground surface, and those
connections that are on such portions of the cover (e.g., fill ports,
access hatches, gauge wells, etc.) and can be opened to the atmosphere.
(ii) You must initially conduct the inspections specified in
paragraph (a)(3)(i) of this section following the installation of the
cover. Thereafter, you must perform the inspection at least once every
calendar year, except as provided in paragraphs (e) and (f) of this
section. You must maintain records of the inspection results as
specified in Sec. 60.5420(c)(7).
(4) For each bypass device, except as provided for in Sec.
60.5411, you must meet the requirements of paragraphs (a)(4)(i) or (ii)
of this section.
(i) Set the flow indicator to take a reading at least once every 15
minutes at the inlet to the bypass device that could divert the steam
away from the control device to the atmosphere.
(ii) If the bypass device valve installed at the inlet to the
bypass device is secured in the non-diverting position using a car-seal
or a lock-and-key type configuration, visually inspect the seal or
closure mechanism at least once every month to verify that the valve is
maintained in the non-diverting position and the vent stream is not
diverted through the bypass device. You must maintain records of the
inspections according to Sec. 60.5420(c)(8).
(b) No detectable emissions test methods and procedures. If you are
required to conduct an inspection of a closed vent system or cover at
your storage vessel or centrifugal compressor affected facility as
specified in paragraphs (a)(1), (2), or (3) of this section, you must
meet the requirements of paragraphs (b)(1) through (13) of this
section.
(1) You must conduct the no detectable emissions test procedure in
accordance with Method 21 at 40 CFR part 60, appendix A-7.
(2) The detection instrument must meet the performance criteria of
Method 21 at 40 CFR part 60, appendix A-7, except that the instrument
response factor criteria in section 3.1.2(a) of Method 21 must be for
the average composition of the fluid and not for each individual
organic compound in the stream.
(3) You must calibrate the detection instrument before use on each
day of its use by the procedures specified in Method 21 at 40 CFR part
60, appendix A-7.
(4) Calibration gases must be as specified in paragraphs (b)(4)(i)
and (ii) of this section.
(i) Zero air (less than 10 parts per million by volume hydrocarbon
in air).
(ii) A mixture of methane in air at a concentration less than
10,000 parts per million by volume.
(5) You may choose to adjust or not adjust the detection instrument
readings to account for the background organic concentration level. If
you choose to adjust the instrument readings for the background level,
you must determine the background level value according to the
procedures in Method 21 at 40 CFR part 60, appendix A-7.
(6) Your detection instrument must meet the performance criteria
specified in paragraphs (b)(6)(i) and (ii) of this section.
(i) Except as provided in paragraph (b)(6)(ii) of this section, the
detection instrument must meet the performance criteria of Method 21 at
40 CFR part 60, appendix A-7, except the instrument response factor
criteria in section 3.1.2(a) of Method 21 must be for the average
composition of the process fluid, not each individual volatile organic
compound in the stream. For
[[Page 49559]]
process streams that contain nitrogen, air, or other inerts that are
not organic hazardous air pollutants or volatile organic compounds, you
must calculate the average stream response factor on an inert-free
basis.
(ii) If no instrument is available that will meet the performance
criteria specified in paragraph (b)(6)(i) of this section, you may
adjust the instrument readings by multiplying by the average response
factor of the process fluid, calculated on an inert-free basis, as
described in paragraph (b)(6)(i) of this section.
(7) You must determine if a potential leak interface operates with
no detectable emissions using the applicable procedure specified in
paragraph (b)(7)(i) or (ii) of this section.
(i) If you choose not to adjust the detection instrument readings
for the background organic concentration level, then you must directly
compare the maximum organic concentration value measured by the
detection instrument to the applicable value for the potential leak
interface as specified in paragraph (b)(8) of this section.
(ii) If you choose to adjust the detection instrument readings for
the background organic concentration level, you must compare the value
of the arithmetic difference between the maximum organic concentration
value measured by the instrument and the background organic
concentration value as determined in paragraph (b)(5) of this section
with the applicable value for the potential leak interface as specified
in paragraph (b)(8) of this section.
(8) A potential leak interface is determined to operate with no
detectable organic emissions if the organic concentration value
determined in paragraph (b)(7) of this section is less than 500 parts
per million by volume.
(9) Repairs. In the event that a leak or defect is detected, you
must repair the leak or defect as soon as practicable according to the
requirements of paragraphs (b)(9)(i) and (ii) of this section, except
as provided in paragraph (d) of this section.
(i) A first attempt at repair must be made no later than 5 calendar
days after the leak is detected.
(ii) Repair must be completed no later than 15 calendar days after
the leak is detected.
(10) Delay of repair. Delay of repair of a closed vent system or
cover for which leaks or defects have been detected is allowed if the
repair is technically infeasible without a shutdown, or if you
determine that emissions resulting from immediate repair would be
greater than the fugitive emissions likely to result from delay of
repair. You must complete repair of such equipment by the end of the
next shutdown.
(11) Unsafe to inspect requirements. You may designate any parts of
the closed vent system or cover as unsafe to inspect if the
requirements in paragraphs (e)(1) and (2) of this section are met.
Unsafe to inspect parts are exempt from the inspection requirements of
paragraphs (a)(1) through (3) of this section.
(A) You determine that the equipment is unsafe to inspect because
inspecting personnel would be exposed to an imminent or potential
danger as a consequence of complying with paragraphs (a)(1), (2), or
(3) of this section.
(B) You have a written plan that requires inspection of the
equipment as frequently as practicable during safe-to-inspect times.
(12) Difficult to inspect requirements. You may designate any parts
of the closed vent system or cover as difficult to inspect, if the
requirements in paragraphs (b)(12)(i) and (ii) of this section are met.
Difficult to inspect parts are exempt from the inspection requirements
of paragraphs (a)(1) through (3) of this section.
(i) You determine that the equipment cannot be inspected without
elevating the inspecting personnel more than 2 meters above a support
surface.
(ii) You have a written plan that requires inspection of the
equipment at least once every 5 years.
(13) Records. Records shall be maintained as specified in this
section and in Sec. 60.5420(c)(9).
Sec. 60.5417 What are the continuous control device monitoring
requirements for my storage vessel or centrifugal compressor affected
facility?
You must meet the applicable requirements of this section to
demonstrate continuous compliance for each control device used to meet
emission standards for your storage vessel or centrifugal compressor
affected facility.
(a) You must install and operate a continuous parameter monitoring
system for each control device as specified in paragraphs (c) through
(j) of this section, except as provided for in paragraph (b) of this
section. If you install and operate a flare in accordance with Sec.
60.5412(a)(3), you are exempt from the requirements of paragraphs (e)
and (f) of this section.
(b) You are exempt from the monitoring requirements specified in
paragraphs (c) through (j) of this section for the control devices
listed in paragraphs (b)(1) and (2) of this section.
(1) A boiler or process heater in which all vent streams are
introduced with the primary fuel or is used as the primary fuel.
(2) A boiler or process heater with a design heat input capacity
equal to or greater than 44 megawatts.
(c) You must design and operate the continuous monitoring system so
that a determination can be made on whether the control device is
achieving the applicable performance requirements of Sec. 60.5412. For
each continuous parameter monitoring system, you must meet the
specifications and requirements in paragraphs (c)(1) through (4) of
this section.
(1) Each continuous parameter monitoring system must measure data
values at least once every hour and record the parameters in paragraphs
(c)(1)(i) or (ii) of this section.
(i) Each measured data value.
(ii) Each block average value for each 1-hour period or shorter
periods calculated from all measured data values during each period. If
values are measured more frequently than once per minute, a single
value for each minute may be used to calculate the hourly (or shorter
period) block average instead of all measured values.
(2) You must prepare a site-specific monitoring plan that addresses
the monitoring system design, data collection, and the quality
assurance and quality control elements outlined in paragraphs (c)(2)(i)
through (v) of this section. You must install, calibrate, operate, and
maintain each continuous parameter monitoring system in accordance with
the procedures in your approved site-specific monitoring plan.
(i) The performance criteria and design specifications for the
monitoring system equipment, including the sample interface, detector
signal analyzer, and data acquisition and calculations.
(ii) Sampling interface (e.g., thermocouple) location such that the
monitoring system will provide representative measurements.
(iii) Equipment performance checks, system accuracy audits, or
other audit procedures.
(iv) Ongoing operation and maintenance procedures in accordance
with provisions in Sec. 60.13(b).
(v) Ongoing reporting and recordkeeping procedures in accordance
with provisions in Sec. 60.7(c), (d), and (f).
(3) You must conduct the continuous parameter monitoring system
equipment performance checks, system accuracy audits, or other audit
procedures specified in the site-specific monitoring plan at least once
every 12 months.
(4) You must conduct a performance evaluation of each continuous
parameter monitoring system in
[[Page 49560]]
accordance with the site-specific monitoring plan.
(d) You must install, calibrate, operate, and maintain a device
equipped with a continuous recorder to measure the values of operating
parameters appropriate for the control device as specified in either
paragraph (d)(1), (2), or (3) of this section.
(1) A continuous monitoring system that measures the operating
parameters in paragraphs (d)(1)(i) through (viii) of this section, as
applicable.
(i) For a thermal vapor incinerator that demonstrates during the
performance test conducted under Sec. 60.5413 that combustion zone
temperature is an accurate indicator of performance, a temperature
monitoring device equipped with a continuous recorder. The monitoring
device must have a minimum accuracy of 1 percent of the
temperature being monitored in [deg]C, or 2.5 [deg]C,
whichever value is greater. You must install the temperature sensor at
a location representative of the combustion zone temperature.
(ii) For a catalytic vapor incinerator, a temperature monitoring
device equipped with a continuous recorder. The device must be capable
of monitoring temperature at two locations and have a minimum accuracy
of 1 percent of the temperature being monitored in [deg]C,
or 2.5 [deg]C, whichever value is greater. You must install
one temperature sensor in the vent stream at the nearest feasible point
to the catalyst bed inlet, and you must install a second temperature
sensor in the vent stream at the nearest feasible point to the catalyst
bed outlet.
(iii) For a flare, a heat sensing monitoring device equipped with a
continuous recorder that indicates the continuous ignition of the pilot
flame.
(iv) For a boiler or process heater, a temperature monitoring
device equipped with a continuous recorder. The temperature monitoring
device must have a minimum accuracy of 1 percent of the
temperature being monitored in [deg]C, or 2.5 [deg]C,
whichever value is greater. You must install the temperature sensor at
a location representative of the combustion zone temperature.
(v) For a condenser, a temperature monitoring device equipped with
a continuous recorder. The temperature monitoring device must have a
minimum accuracy of 1 percent of the temperature being
monitored in [deg]C, or 2.8 [deg]C, whichever value is
greater. You must install the temperature sensor at a location in the
exhaust vent stream from the condenser.
(vi) For a regenerative-type carbon adsorption system, a continuous
monitoring system that meets the specifications in paragraphs
(d)(1)(vi)(A) and (B) of this section.
(A) The continuous parameter monitoring system must 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. You must check the
mechanical connections for leakage at least every month, and you must
perform a visual inspection at least every 3 months of all components
of the flow continuous parameter monitoring system for physical and
operational integrity and all electrical connections for oxidation and
galvanic corrosion if your flow continuous parameter monitoring system
is not equipped with a redundant flow sensor; and
(B) The continuous parameter monitoring system must measure and
record the average carbon bed temperature for the duration of the
carbon bed steaming cycle and measure the actual carbon bed temperature
after regeneration and within 15 minutes of completing the cooling
cycle. The temperature monitoring device must have a minimum accuracy
of 1 percent of the temperature being monitored in [deg]C,
or 2.5 [deg]C, whichever value is greater.
(vii) For a nonregenerative-type carbon adsorption system, you must
monitor the design carbon replacement interval established using a
performance test performed as specified in Sec. 60.5413(b). The design
carbon replacement interval must be based on the total carbon working
capacity of the control device and source operating schedule.
(viii) For a combustion control device whose model is tested under
Sec. 60.5413(d), a continuous monitoring system meeting the
requirements of paragraphs (d)(1)(viii)(A) and (B) of this section.
(A) The continuous monitoring system must measure gas flow rate at
the inlet to the control device. The monitoring instrument must have an
accuracy of 2 percent or better.
(B) A heat sensing monitoring device equipped with a continuous
recorder that indicates the continuous ignition of the pilot flame.
(2) A continuous monitoring system that measures the concentration
level of organic compounds in the exhaust vent stream from the control
device using an organic monitoring device equipped with a continuous
recorder. The monitor must meet the requirements of Performance
Specification 8 or 9 of 40 CFR part 60, appendix B. You must install,
calibrate, and maintain the monitor according to the manufacturer's
specifications.
(3) A continuous monitoring system that measures operating
parameters other than those specified in paragraph (d)(1) or (2) of
this section, upon approval of the Administrator as specified in Sec.
60.13(i).
(e) You must calculate the daily average value for each monitored
operating parameter for each operating day, using the data recorded by
the monitoring system, except for inlet gas flow rate. 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.
(f) For each operating parameter monitor installed in accordance
with the requirements of paragraph (d) of this section, you must comply
with paragraph (f)(1) of this section for all control devices. When
condensers are installed, you must also comply with paragraph (f)(2) of
this section.
(1) You must 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. 60.5412(a). You must establish each minimum or
maximum operating parameter value as specified in paragraphs (f)(1)(i)
through (iii) of this section.
(i) If you conduct performance tests in accordance with the
requirements of Sec. 60.5413(b) to demonstrate that the control device
achieves the applicable performance requirements specified in Sec.
60.5412(a), then you must establish the minimum operating parameter
value or the maximum operating parameter value 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.
(ii) If you use a condenser design analysis in accordance with the
requirements of Sec. 60.5413(c) to demonstrate that the control device
achieves the applicable performance requirements specified in Sec.
60.5412(a), then you must establish the minimum
[[Page 49561]]
operating parameter value or the maximum operating parameter value
based on the condenser design analysis and supplemented, as necessary,
by the condenser manufacturer's recommendations.
(iii) If you operate a control device where the performance test
requirement was met under Sec. 60.5413(d) to demonstrate that the
control device achieves the applicable performance requirements
specified in Sec. 60.5412(a), then you must establish the maximum
inlet gas flow rate based on the performance test and supplemented, as
necessary, by the manufacturer recommendations.
(2) If you use a condenser as specified in paragraph (d)(1)(v) of
this section, you must establish a condenser performance curve showing
the relationship between condenser outlet temperature and condenser
control efficiency, according to the requirements of paragraphs
(f)(2)(i) and (ii) of this section.
(i) If you conduct a performance test in accordance with the
requirements of Sec. 60.5413(b) to demonstrate that the condenser
achieves the applicable performance requirements in Sec. 60.5412(a),
then the condenser performance curve must 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.
(ii) If you use a control device design analysis in accordance with
the requirements of Sec. 60.5413(c)(1) to demonstrate that the
condenser achieves the applicable performance requirements specified in
Sec. 60.5412(a), then the condenser performance curve must be based on
the condenser design analysis and supplemented, as necessary, by the
control device manufacturer's recommendations.
(g) A deviation 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 (g)(1) through (g)(6)
of this section being met. If you monitor multiple operating parameters
for the same control device during the same operating day and more than
one of these operating parameters meets a deviation criterion specified
in paragraphs (g)(1) through (6) of this section, then a single
excursion is determined to have occurred for the control device for
that operating day.
(1) A deviation occurs when the daily average value of a monitored
operating parameter is less than the minimum operating parameter limit
(or, if applicable, greater than the maximum operating parameter limit)
established in paragraph (f)(1) of this section.
(2) If you meet Sec. 60.5412(a)(2), a deviation occurs when the
365-day average condenser efficiency calculated according to the
requirements specified in Sec. 60.5415(e)(8)(iv) is less than 95.0
percent.
(3) If you meet Sec. 60.5412(a)(2) and you have less than 365 days
of data, a deviation occurs when the average condenser efficiency
calculated according to the procedures specified in Sec.
60.5415(e)(8)(iv)(A) or (B) is less than 90.0 percent.
(4) A deviation occurs when the monitoring data are not available
for at least 75 percent of the operating hours in a day.
(5) If the closed vent system contains one or more bypass devices
that could be used to divert all or a portion of the gases, vapors, or
fumes from entering the control device, a deviation occurs when the
requirements of paragraphs (g)(5)(i) and (ii) of this section are met.
(i) For each bypass line subject to Sec. 60.5411(a)(3)(i)(A), the
flow indicator indicates that flow has been detected and that the
stream has been diverted away from the control device to the
atmosphere.
(ii) For each bypass line subject to Sec. 60.5411(a)(3)(i)(B), if
the seal or closure mechanism has been broken, the bypass line valve
position has changed, the key for the lock-and-key type lock has been
checked out, or the car-seal has broken.
(6) For a combustion control device whose model is tested under
Sec. 60.5413(d), a deviation occurs when the conditions of paragraphs
(g)(6)(i) or (ii) are met.
(i) The inlet gas flow rate exceeds the maximum established during
the test conducted under Sec. 60.5413(d).
(ii) Failure of the monthly visible emissions test conducted under
Sec. 60.5415(e)(7)(iii) occurs.
Sec. 60.5420 What are my notification, reporting, and recordkeeping
requirements?
(a) You must submit the notifications required in Sec. 60.7(a)(1)
and (4), and according to paragraphs (a)(1) and (2) of this section, if
you own or operate one or more of the affected facilities specified in
Sec. 60.5365 that was constructed, modified, or reconstructed during
the reporting period.
(1) If you own or operate a gas well, pneumatic controller or
storage vessel affected facility you are not required to submit the
notifications required in Sec. 60.7(a)(1), (3), and (4).
(2)(i) If you own or operate a gas well affected facility, you must
submit a notification to the Administrator no later than 2 days prior
to the commencement of each well completion operation listing the
anticipated date of the well completion operation. The notification
shall include contact information for the owner or operator; the API
well number, the latitude and longitude coordinates for each well in
decimal degrees to an accuracy and precision of five (5) decimals of a
degree using the North American Datum of 1983; and the planned date of
the beginning of flowback. You may submit the notification in writing
or in electronic format.
(ii) If you are subject to state regulations that require advance
notification of well completions and you have met those notification
requirements, then you are considered to have met the advance
notification requirements of paragraph (a)(2)(i) of this section.
(b) Reporting requirements. You must submit annual reports
containing the information specified in paragraphs (b)(1) through (6)
of this section to the Administrator and performance test reports as
specified in paragraph (b)(7) of this section. The initial annual
report is due 30 days after the end of the initial compliance period as
determined according to Sec. 60.5410. 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 (6)
of this section. Annual reports may coincide with title V reports as
long as all the required elements of the annual report are included.
You may arrange with the Administrator a common schedule on which
reports required by this part may be submitted as long as the schedule
does not extend the reporting period.
(1) The general information specified in paragraphs (b)(1)(i)
through (iv) 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.
(iv) A certification by a responsible official of truth, accuracy,
and completeness. This certification shall state that, based on
information and belief formed after reasonable inquiry, the statements
and information in the document are true, accurate, and complete.
[[Page 49562]]
(2) For each gas well affected facility, the information in
paragraphs (b)(2)(i) through (ii) of this section.
(i) Records of each well completion operation as specified in
paragraph (c)(1)(i) through (iv) of this section for each gas well
affected facility conducted during the reporting period. In lieu of
submitting the records specified in paragraph (c)(1)(i) through (iv),
the owner or operator may submit a list of the well completions with
hydraulic fracturing completed during the reporting period and the
records required by paragraph (c)(1)(v) of this section for each well
completion.
(ii) Records of deviations specified in paragraph (c)(1)(ii) of
this section that occurred during the reporting period.
(3) For each centrifugal compressor affected facility, the
information specified in paragraphs (b)(3)(i) and (ii) of this section.
(i) An identification of each centrifugal compressor using a wet
seal system constructed, modified or reconstructed during the reporting
period.
(ii) Records of deviations specified in paragraph (c)(2) of this
section that occurred during the reporting period.
(iii) If required to comply with Sec. 60.5380(a)(1), the records
of closed vent system and cover inspections specified in paragraph
(c)(6) of this section.
(4) For each reciprocating compressor affected facility, the
information specified in paragraphs (b)(4)(i) through (ii) of this
section.
(i) The cumulative number of hours or operation or the number of
months since initial startup, October 15, 2012, or since the previous
reciprocating compressor rod packing replacement, whichever is later.
(ii) Records of deviations specified in paragraph (c)(3)(iii) of
this section that occurred during the reporting period.
(5) For each pneumatic controller affected facility, the
information specified in paragraphs (b)(5)(i) through (v) of this
section.
(i) An identification of each pneumatic controller constructed,
modified or reconstructed during the reporting period, including the
identification information specified in Sec. 60.5390(c)(2).
(ii) If applicable, documentation that the use of pneumatic
controller affected facilities with a natural gas bleed rate greater
than 6 standard cubic feet per hour are required and the reasons why.
(iii) Records of deviations specified in paragraph (c)(4)(v) of
this section that occurred during the reporting period.
(6) For each storage vessel affected facility, the information in
paragraphs (b)(6)(i) through (iii) of this section.
(i) An identification of each storage vessel with VOC emissions
greater than 6 tpy constructed, modified or reconstructed during the
reporting period.
(ii) Documentation that the VOC emission rate is less than 6 tpy
for meeting the requirements in Sec. 60.5395(a).
(iii) Records of deviations specified in paragraph (c)(5)(iii) of
this section that occurred during the reporting period.
(7)(i) Within 60 days after the date of completing each performance
test (see Sec. 60.8 of this part) as required by this subpart you must
submit the results of the performance tests required by this subpart to
EPA's WebFIRE database by using the Compliance and Emissions Data
Reporting Interface (CEDRI) that is accessed through EPA's Central Data
Exchange (CDX) (www.epa.gov/cdx). Performance test data must be
submitted in the file format generated through use of EPA's Electronic
Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/index.html).
Only data collected using test methods on the ERT Web site are subject
to this requirement for submitting reports electronically to WebFIRE.
Owners or operators who claim that some of the information being
submitted for performance tests is confidential business information
(CBI) must submit a complete ERT file including information claimed to
be CBI on a compact disk or other commonly used electronic storage
media (including, but not limited to, flash drives) to EPA. The
electronic media must be clearly marked as CBI and mailed to U.S. EPA/
OAPQS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404-02,
4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI
omitted must be submitted to EPA via CDX as described earlier in this
paragraph. At the discretion of the delegated authority, you must also
submit these reports, including the confidential business information,
to the delegated authority in the format specified by the delegated
authority.
(ii) All reports required by this subpart not subject to the
requirements in paragraph (a)(2)(i) of this section must be sent to the
Administrator at the appropriate address listed in Sec. 63.13 of this
part. The Administrator or the delegated authority may request a report
in any form suitable for the specific case (e.g., by commonly used
electronic media such as Excel spreadsheet, on CD or hard copy). The
Administrator retains the right to require submittal of reports subject
to paragraph (a)(2)(i) and (ii) of this section in paper format.
(c) Recordkeeping requirements. You must maintain the records
identified as specified in Sec. 60.7(f) and in paragraphs (c)(1)
through (10) of this section. All records must be maintained for at
least 5 years.
(1) The records for each gas well affected facility as specified in
paragraphs (c)(1)(i) through (v) of this section.
(i) Records identifying each well completion operation for each gas
well affected facility;
(ii) Records 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 well affected facility that
occurred during the reporting period. You must maintain the records
specified in paragraphs (c)(1)(iii)(A) and (B) of this section.
(A) For each gas well affected facility required to comply with the
requirements of Sec. 60.5375(a), you must record: The location of the
well; the API well number; the duration of flowback; duration of
recovery to the flow 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 well 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 flow line.
(iv) For each gas well facility for which you claim an exception
under Sec. 60.5375(a)(3), you must record: The location of the well;
the API well number; the specific exception claimed; the starting date
and ending date for the period the well operated under the exception;
and an explanation of why the well meets the claimed exception.
(v) For each gas well affected facility required to comply with
both Sec. 60.5375(a)(1) and (3), records of the digital photograph as
specified in Sec. 60.5410(a)(4).
(2) For each centrifugal compressor affected facility, you must
maintain records of deviations in cases where the centrifugal
compressor was not operated in compliance with the requirements
specified in Sec. 60.5380.
(3) For each reciprocating compressors affected facility, you must
maintain the records in paragraphs (c)(3)(i) through (iii) of this
section.
[[Page 49563]]
(i) Records of the cumulative number of hours of operation or
number of months since initial startup or October 15, 2012, 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.
(iii) Records of deviations in cases where the reciprocating
compressor was not operated in compliance with the requirements
specified in Sec. 60.5385.
(4) For each pneumatic controller affected facility, you must
maintain the records identified in paragraphs (c)(4)(i) through (v) of
this section.
(i) Records of the date, location and manufacturer specifications
for each pneumatic controller constructed, modified or reconstructed.
(ii) Records of the demonstration that the use of pneumatic
controller affected facilities with a natural gas bleed rate greater
than 6 standard cubic feet per hour are required and the reasons why.
(iii) If the pneumatic controller is not located at a natural gas
processing plant, records of the manufacturer's specifications
indicating that the controller is designed such that natural gas bleed
rate is less than or equal to 6 standard cubic feet per hour.
(iv) If the pneumatic controller is located at a natural gas
processing plant, records of the documentation that the natural gas
bleed rate is zero.
(v) Records of deviations in cases where the pneumatic controller
was not operated in compliance with the requirements specified in Sec.
60.5390.
(5) For each storage vessel affected facility, you must maintain
the records identified in paragraphs (c)(5)(i) through (iv) of this
section.
(i) If required to reduce emissions by complying with Sec.
60.5395, the records specified in Sec. 60.5416 of this subpart.
(ii) Records of the determination that the VOC emission rate is
less than 6 tpy per storage vessel for the exemption under Sec.
60.5395(a), including identification of the model or calculation
methodology used to calculate the VOC emission rate.
(iii) Records of deviations in cases where the storage vessel was
not operated in compliance with the requirements specified in
Sec. Sec. 60.5395, 60.5411, 60.5412, and 60.5413.
(iv) For vessels that are skid-mounted or permanently attached to
something that is mobile (such as trucks, railcars, barges or ships),
records indicating the number of consecutive days that the vessel is
located at a site in the oil and natural gas production segment,
natural gas processing segment or natural gas transmission and storage
segment. If a vessel is removed from a site and, within 30 days, is
either returned to or replaced by another vessel at the site to serve
the same or similar function, then the entire period since the original
vessel was first located at the site, including the days when the
storage vessel was removed, will be added to the count towards the
number of consecutive days.
(6) For each storage vessel or centrifugal compressor subject to
the closed vent system inspection requirements of Sec. 60.5416(a)(1)
and (2), records of each inspection.
(7) For each storage vessel or centrifugal compressor subject to
the cover requirements of Sec. 60.5416(a)(3), a record of each
inspection.
(8) For each storage vessel or centrifugal compressor subject to
the bypass requirements of Sec. 60.5416(a)(4), a record of each
inspection or a record each time the key is checked out or a record of
each time the alarm is sounded.
(9) For each closed vent system used to comply with this subpart
that must operate with no detectable emissions, a record of the
monitoring conducted in accordance with Sec. 60.5416(b)(13).
(10) Records of the schedule for carbon replacement (as determined
by the design analysis requirements of Sec. 60.5413(c)(2) or (3)) and
records of each carbon replacement as specified in Sec. 60.5412(c)(1).
(11) For each storage vessel or centrifugal compressor subject to
the control device requirements of Sec. 60.5412, records of minimum
and maximum operating parameter values, continuous parameter monitoring
system data, calculated averages of continuous parameter monitoring
system data, results of all compliance calculations, and results of all
inspections.
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.
(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):
[[Page 49564]]
(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 report of excess emissions to the
Administrator in your annual report if you had excess emissions during
the reporting period. 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.
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.
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.
Bleed rate means the rate in standard cubic feet per hour at which
natural gas is continuously vented (bleeds) from a pneumatic
controller.
Centrifugal compressor means any machine for raising the pressure
of a natural gas by drawing in low pressure natural gas and discharging
significantly higher pressure natural gas by means of mechanical
rotating vanes or impellers. Screw, sliding vane, and liquid ring
compressors are not centrifugal compressors for the purposes of this
subpart.
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.
Compressor station means any permanent combination of one or more
compressors that move natural gas at increased pressure from fields, in
transmission pipelines, or into storage.
Continuous bleed means a continuous flow of pneumatic supply
natural gas to the process control device (e.g., level control,
temperature control, pressure control) where the supply gas pressure is
modulated by the process condition, and then flows to the valve
controller where the signal is compared with the process set-point to
adjust gas pressure in the valve actuator.
Custody transfer means the transfer of natural gas after processing
and/or treatment in the producing operations, or from storage vessels
or automatic transfer facilities or other such equipment, including
product loading racks, to pipelines or any other forms of
transportation.
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).
Deviation means any instance in which an affected source subject to
this subpart, or an owner or operator of such a source:
(1) Fails to meet any requirement or obligation established by this
subpart including, but not limited to, any emission limit, operating
limit, or work practice standard;
(2) Fails to meet any term or condition that is adopted to
implement an applicable requirement in this subpart and that is
included in the operating permit for any affected source required to
obtain such a permit; or
(3) Fails to meet any emission limit, operating limit, or work
practice standard in this subpart during startup, shutdown, or
malfunction, regardless of whether or not such failure is permitted by
this subpart.
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, 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 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. Completion combustion devices as defined in this
section are not considered flares.
Flow line means a pipeline used to transport oil and/or gas from
the well to a processing facility, a mainline pipeline, re-injection,
or other useful purpose.
Flowback means the process of allowing fluids to flow from a
natural
[[Page 49565]]
gas well following a treatment, either in preparation for a subsequent
phase of treatment or in preparation for cleanup and returning the well
to production. The flowback period begins when material introduced into
the well during the treatment returns to the surface immediately
following hydraulic fracturing or refracturing. The flowback period
ends with either well shut in or when the well is producing
continuously to the flow line or to a storage vessel for collection,
whichever occurs first.
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 or natural gas well means an onshore well drilled
principally for production of natural gas.
Hydraulic fracturing or refracturing means the process of directing
pressurized fluids containing any combination of water, proppant, and
any added chemicals to penetrate tight formations, such as shale or
coal formations, that subsequently require high rate, extended flowback
to expel fracture fluids and solids during completions.
Hydraulic refracturing means conducting a subsequent hydraulic
fracturing operation at a well that has previously undergone a
hydraulic fracturing operation.
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(g)(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.
Intermittent/snap-action pneumatic controller means a pneumatic
controller that vents non-continuously.
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 pressure gas well means a well with reservoir pressure and
vertical well depth such that 0.445 times the reservoir pressure (in
psia) minus 0.038 times the vertical well depth (in feet) minus 67.578
psia is less than the flow line pressure at the sales meter.
Natural gas-driven pneumatic controller means a pneumatic
controller powered by pressurized natural gas.
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. A Joule-Thompson valve, a dew point depression valve, or an
isolated or standalone Joule-Thompson skid is not a natural gas
processing plant.
Natural gas transmission means the pipelines used for the long
distance transport of natural gas (excluding processing). Specific
equipment used in natural gas transmission includes the land, mains,
valves, meters, boosters, regulators, storage vessels, dehydrators,
compressors, and their driving units and appurtenances, and equipment
used for transporting gas from a production plant, delivery point of
purchased gas, gathering system, storage area, or other wholesale
source of gas to one or more distribution area(s).
Nonfractionating plant means any gas plant that does not
fractionate mixed natural gas liquids into natural gas products.
Non-natural gas-driven pneumatic controller 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.
Pneumatic controller means an automated instrument used for
maintaining a process condition such as liquid level, pressure, delta-
pressure and temperature.
Pressure vessel means a storage vessel that is used to store
liquids or gases and is designed not to vent to the atmosphere as a
result of compression of the vapor headspace in the pressure vessel
during filling of the pressure vessel to its design capacity.
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 following
fracturing or refracturing where gas flowback that is otherwise vented
is captured, cleaned, and routed to the flow line or collection system,
re-injected into the well or another well, used as an on-site fuel
source, or used for other useful purpose that a purchased fuel or raw
material would serve, with no direct release to the atmosphere.
Reduced sulfur compounds means H2S, carbonyl sulfide
(COS), and carbon disulfide (CS2).
Responsible official means one of the following:
(1) For a corporation: A president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business
function, or any other person who performs similar policy or decision-
making functions for the corporation, or a duly authorized
representative of such person if the representative is responsible for
the overall operation of one or more manufacturing, production, or
operating facilities applying for or subject to a permit and either:
(i) The facilities employ more than 250 persons or have gross
annual sales or expenditures exceeding $25 million (in second quarter
1980 dollars); or
(ii) The delegation of authority to such representatives is
approved in advance by the permitting authority;
(2) For a partnership or sole proprietorship: A general partner or
the proprietor, respectively;
(3) For a municipality, State, Federal, or other public agency:
Either a principal executive officer or ranking elected official. For
the purposes of this part, a principal executive officer of a Federal
agency includes the chief executive officer having responsibility for
the overall operations of a principal geographic unit of the agency
(e.g., a Regional Administrator of EPA); or
(4) For affected facilities:
(i) The designated representative in so far as actions, standards,
requirements, or prohibitions under title IV of the Clean Air Act or
the regulations promulgated thereunder are concerned; or
(ii) The designated representative for any other purposes under
part 60.
[[Page 49566]]
Routed to a process or route to a process means the emissions are
conveyed via a closed vent system 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,
regardless of whether such gas is sold.
Storage vessel means a unit that is constructed primarily of
nonearthen materials (such as wood, concrete, steel, fiberglass, or
plastic) which provides structural support and is designed to contain
an accumulation of liquids or other materials. The following are not
considered storage vessels:
(1) Vessels that are skid-mounted or permanently attached to
something that is mobile (such as trucks, railcars, barges or ships),
and are intended to be located at a site for less than 180 consecutive
days. If you do not keep or are not able to produce records, as
required by Sec. 60.5420(c)(5)(iv), showing that the vessel has been
located at a site for less than 180 consecutive days, the vessel
described herein is considered to be a storage vessel since the
original vessel was first located at the site.
(2) Process vessels such as surge control vessels, bottoms
receivers or knockout vessels.
(3) Pressure vessels designed to operate in excess of 204.9
kilopascals and without emissions to the atmosphere.
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 sour 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 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 vessel means a storage vessel 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 flowback of
petroleum or natural gas from newly drilled wells to expel drilling and
reservoir fluids and tests the reservoir flow characteristics, which
may vent produced hydrocarbons to the atmosphere via an open pit or
tank.
Well completion operation means any well completion with hydraulic
fracturing or refracturing occurring at a gas well affected facility.
Well site means one or more 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 <= 15.0 < X <=
5.0 5.0 < X <= 15.0 300.0 X > 300.0
----------------------------------------------------------------------------------------------------------------
Y >= 50............................... 79.0 88.51X\0.0101\Y\0.0125\ or 99.9, whichever is smaller.
---------------------------------------------------------
20 <= Y < 50.......................... 79.0 88.5X\0.0101\Y\0.0125\ or 97.9, 97.9
whichever is smaller.
------------------------------------------
10 <= Y < 20.......................... 79.0 88.5X\0.0101\Y\0.0125\ 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 <= 15.0 < X <=
5.0 5.0 < X <= 15.0 300.0 X > 300.0
----------------------------------------------------------------------------------------------------------------
Y >= 50............................... 74.0 85.35X\0.0144\Y\0.0128\ or 99.9, whichever is smaller.
---------------------------------------------------------
20 <= Y < 50.......................... 74.0 85.35X\0.0144\Y\0.0128\ or 97.9, 97.5
whichever is smaller.
---------------------------------------------------------
10 <= Y < 20.......................... 74.0 85.35X\0.0144\Y\0.0128\ or 90.8, 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.
[[Page 49567]]
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.
As stated in Sec. 60.5425, you must comply with the following
applicable General Provisions:
Table 3 to Subpart OOOO of Part 60--Applicability of General Provisions to Subpart OOOO
----------------------------------------------------------------------------------------------------------------
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).
Sec. 60.8.................. Performance tests....... Yes.......................... Performance testing is
required for control
devices used on storage
vessels and centrifugal
compressors.
Sec. 60.9.................. Availability of Yes. ........................
information.
Sec. 60.10................. State authority......... Yes. ........................
Sec. 60.11................. Compliance with No........................... Requirements are
standards and specified in subpart
maintenance OOOO.
requirements.
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.......................... Except that Sec. 60.18
requirements. does not apply to
flares.
Sec. 60.19................. General notification and Yes. ........................
reporting requirement.
----------------------------------------------------------------------------------------------------------------
PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS
FOR SOURCE CATEGORIES
0
8. The authority citation for part 63 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
0
9. Section 63.14 is amended by:
0
a. Revising paragraphs (b) introductory text, (b)(28), and (b)(64);
0
b. Adding paragraphs (b)(73), (74), and (75); and
0
c. Revising paragraphs (i) introductory text and (i)(1) to read as
follows:
Sec. 63.14 Incorporations by reference.
* * * * *
(b) The following materials are available for purchase from at
least one of the following addresses: American Society for Testing and
Materials (ASTM), 100 Barr Harbor Drive, Post Office Box C700, West
Conshohocken, PA 19428-2959, Telephone (610) 832-9585, and are also
available at the following Web site: http://www.astm.org; or ProQuest,
789 East Eisenhower Parkway, Ann Arbor, MI 48106-1346, Telephone (734)
761-4700, and are also available at the following Web site: http://www.proquest.com.
* * * * *
(28) ASTM D6420-99 (Reapproved 2004), Standard Test Method for
Determination of Gaseous Organic Compounds by Direct Interface Gas
Chromatography-Mass Spectrometry (Approved October 1, 2004), IBR
approved for Sec. Sec. 60.485(g), 60.485a(g), 63.772(a), 63.772(e),
63.1282(a), 63.1282(d), 63.2351(b), 63.2354(b) and table 8 to subpart
HHHHHHH of this part.
* * * * *
(64) ASTM D6522-00 (Reapproved 2005), Standard Test Method for
Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen
Concentrations in Emissions from Natural Gas Fired Reciprocating
Engines, Combustion Turbines, Boilers, and Process Heaters Using
Portable Analyzers, approved October 1, 2005, IBR approved for table 4
to subpart ZZZZ of this part, table 5 to subpart DDDDD of this part,
table 4 to subpart JJJJJJ of this part and Sec. Sec. 63.772(e),
63.772(h), 63.1282(d) and 63.1282(g).
* * * * *
(73) ASTM D1945-03 (Reapproved 2010) Standard Test Method for
Analysis of Natural Gas by Gas Chromatography (Approved January 1,
2010), IBR approved for Sec. Sec. 63.772(h) and 63.1282(g).
(74) ASTM D3588-98 (Reapproved 2003) Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density of
Gaseous Fuels (Approved May 10, 2003), IBR approved for Sec. Sec.
63.772(h) and 63.1282(g).
(75) ASTM D4891-89 (Reapproved 2006) Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion (Approved June 1, 2006), IBR approved for Sec. Sec.
63.772(h) and 63.1282(g).
* * * * *
(i) The following material is available for purchase from at least
one of the following addresses: American Society of Mechanical
Engineers (ASME), Three Park Avenue, New York, NY 10016-
[[Page 49568]]
5990, Telephone (800) 843-2763, and are also available at the following
Web site: http://www.asme.org; or HIS, Incorporated, 15 Inverness Way
East, Englewood, CO 80112, Telephone (877) 413-5184, and are also
available at the following Web site: http://global.ihs.com.
(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), 63.772(e), 63.772(h), 63.865(b), 63.1282(d),
63.1282(g), 63.3166(a), 63.3360(e), 63.3545(a), 63.3555(a), 63.4166(a),
63.4362(a), 63.4766(a), 63.4965(a), 63.5160(d), 63.9307(c), 63.9323(a),
63.11148(e), 63.11155(e), 63.11162(f), 63.11163(g), 63.11410(j),
63.11551(a) and 63.11646(a), 63.11945, table 5 to subpart DDDDD of this
part, table 4 to subpart JJJJJ of this part, table 5 to subpart UUUUU
of this part and table 1 to subpart ZZZZZ of this part.
* * * * *
Subpart HH--[Amended]
0
10. Section 63.760 is amended by:
0
a. Revising paragraph (a)(1) introductory text;
0
b. Revising paragraph (a)(1)(i);
0
c. Revising paragraph (a)(1)(iii);
0
d. Revising paragraph (a)(2);
0
e. Revising paragraph (b)(1)(i);
0
f. Adding paragraph (c);
0
g. Revising paragraph (f) introductory text;
0
h. Revising paragraph (f)(1);
0
i. Revising paragraph (f)(2);
0
j. Adding paragraphs (f)(7), (f)(8), and (f)(9); and
0
k. Removing and reserving paragraph (g)(1).
The revisions and additions 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.
(i) If the owner or operator documents, to the Administrator's
satisfaction, a decline in annual natural gas or hydrocarbon liquid
throughput, as appropriate, each year for the 5 years prior to October
15, 2012, the owner or operator shall calculate the maximum natural gas
or hydrocarbon liquid throughput used to determine maximum potential
emissions according to the requirements specified in paragraph
(a)(1)(i)(A) of this section. In all other circumstances, the owner or
operator shall calculate the maximum throughput used to determine
whether a facility is a major source in accordance with the
requirements specified in paragraph (a)(1)(i)(B) of this section.
(A) The maximum natural gas or hydrocarbon liquid throughput is the
average of the annual natural gas or hydrocarbon liquid throughput for
the 3 years prior to October 15, 2012, multiplied by a factor of 1.2.
(B) The maximum natural gas or hydrocarbon liquid throughput is the
highest annual natural gas or hydrocarbon liquid throughput over the 5
years prior to October 15, 2012, multiplied by a factor of 1.2.
* * * * *
(iii) The owner or operator shall determine the maximum values for
other parameters used to calculate emissions as the maximum for the
period over which the maximum natural gas or hydrocarbon liquid
throughput is determined in accordance with paragraph (a)(1)(i)(A) or
(B) of this section. Parameters, 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.
* * * * *
(b) * * *
(1) * * *
(i) Each glycol dehydration unit as specified in paragraphs
(b)(1)(i)(A) through (C) of this section.
(A) Each large glycol dehydration unit;
(B) Each small glycol dehydration unit for which construction
commenced on or before August 23, 2011, is an existing small glycol
dehydration unit; and
(C) Each small glycol dehydration unit for which construction
commenced after August 23, 2011, is a new small glycol dehydration
unit.
* * * * *
(c) Any source that determines it is not a major source but has
actual emissions of 5 tons per year or more of a single HAP, or 12.5
tons per year or more of a combination of HAP (i.e., 50 percent of the
major source thresholds), shall update its major source determination
within 1 year of the prior determination or October 15, 2012, whichever
is later, and each year thereafter, using gas composition data measured
during the preceding 12 months.
* * * * *
(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), (2), and (f)(7) through (9) 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 (6) of this section.
(1) Except as specified in paragraphs (f)(7) through (9) 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 (9) of this
section, the owner or operator of an affected major source, the
construction or reconstruction of which commences on
[[Page 49569]]
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 existing small glycol dehydration unit, as
defined in Sec. 63.761, located at a major source, that commenced
construction before August 23, 2011, must achieve compliance no later
than October 15, 2015, except as provided in Sec. 63.6(i).
(8) Each affected new small glycol dehydration unit, 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 October 15, 2012, whichever is later.
(9) A production field facility, as defined in Sec. 63.761,
constructed on or 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
October 15, 2012 must achieve compliance no later than October 15,
2015, except as provided in Sec. 63.6(i).
* * * * *
0
11. Section 63.761 is amended by:
0
a. Adding, in alphabetical order, definitions for the terms
``affirmative defense,'' ``BTEX,'' ``flare,'' ``large glycol
dehydration unit,'' ``responsible official'' and ``small glycol
dehydration unit'';
0
b. Revising the definitions for ``associated equipment,'' ``glycol
dehydration unit baseline operations,'' and ``storage vessel''; and
0
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.
* * * * *
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 Mg/yr, determined
according to Sec. 63.772(b). A glycol dehydration unit complying with
the 0.9 Mg/yr control option under Sec. 63.765(b)(1)(ii) is considered
to be a large dehydrator.
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.
* * * * *
Responsible official means one of the following:
(1) For a corporation: A president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business
function, or any other person who performs similar policy or decision-
making functions for the corporation, or a duly authorized
representative of such person if the representative is responsible for
the overall operation of one or more manufacturing, production, or
operating facilities applying for or subject to a permit and either:
(i) The facilities employ more than 250 persons or have gross
annual sales or expenditures exceeding $25 million (in second quarter
1980 dollars); or
(ii) The delegation of authority to such representatives is
approved in advance by the permitting authority;
(2) For a partnership or sole proprietorship: a general partner or
the proprietor, respectively;
(3) For a municipality, State, Federal, or other public agency:
Either a principal executive officer or ranking elected official. For
the purposes of this part, a principal executive officer of a Federal
agency includes the chief executive officer having responsibility for
the overall operations of a principal geographic unit of the agency
(e.g., a Regional Administrator of EPA); or
(4) For affected sources:
(i) The designated representative in so far as actions, standards,
requirements, or prohibitions under title IV of the Act or the
regulations promulgated thereunder are concerned; and
(ii) The designated representative for any other purposes under
part 70.
* * * * *
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).
* * * * *
Storage vessel means a tank or other vessel that is designed to
contain an accumulation of crude oil, condensate, intermediate
hydrocarbon liquids, or produced water and that is constructed
primarily of non-earthen materials (e.g., wood, concrete, steel,
plastic) that provide structural support. The following process units
are not considered storage vessels: Surge control vessels and knockout
vessels.
* * * * *
0
12. Section 63.762 is revised to read as follows:
Sec. 63.762 Affirmative defense for violations of emission standards
during malfunction.
(a) The provisions set forth in this subpart shall apply at all
times.
(b) [Reserved]
(c) [Reserved]
(d) In response to an action to enforce the standards set forth in
this subpart, you may assert an affirmative defense to
[[Page 49570]]
a claim for civil penalties for violations 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 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 standard, you must timely meet the reporting requirements in
paragraph (d)(2) of this section, and must prove by a preponderance of
evidence that:
(i) The violation:
(A) Was caused by a sudden, infrequent, and unavoidable failure of
air pollution control 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) Was not part of a recurring pattern indicative of inadequate
design, operation, or maintenance; and
(ii) Repairs were made as expeditiously as possible when a
violation occurred. Off-shift and overtime labor were used, to the
extent practicable to make these repairs; and
(iii) The frequency, amount and duration of the violation
(including any bypass) were minimized to the maximum extent
practicable; and
(iv) If the violation 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
violation 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 violation 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, the purpose
of which is to determine, correct, and eliminate the primary causes of
the malfunction and the violation resulting from the malfunction event
at issue. The analysis shall also specify, using best monitoring
methods and engineering judgment, the amount of any emissions that were
the result of the malfunction.
(2) Report. The owner or operator seeking to assert an affirmative
defense shall submit a written report to the Administrator with all
necessary supporting documentation, that it has met the requirements
set forth in paragraph (d)(1) of this section. This affirmative defense
report shall be included in the first periodic compliance, deviation
report or excess emission report otherwise required after the initial
occurrence of the violation of the relevant standard (which may be the
end of any applicable averaging period). If such compliance, deviation
report or excess emission report is due less than 45 days after the
initial occurrence of the violation, the affirmative defense report may
be included in the second compliance, deviation report or excess
emission report due after the initial occurrence of the violation of
the relevant standard.
0
13. Section 63.764 is amended by:
0
a. Revising paragraph (e)(1) introductory text;
0
b. Revising paragraph (i); and
0
c. Adding paragraph (j).
The revisions and addition read as follows:
Sec. 63.764 General standards.
* * * * *
(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 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.
0
14. Section 63.765 is amended by:
0
a. Revising paragraph (a);
0
b. Revising paragraph (b)(1);
0
c. Revising paragraph (c)(2); and
0
d. Revising paragraph (c)(3).
The revisions 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 large glycol dehydration unit 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 existing small glycol
dehydration unit process vent, as defined in Sec. 63.761, to the limit
determined in Equation 1 of this section. You must limit BTEX emissions
from each new small glycol dehydration unit process vent, as defined in
Sec. 63.761, to the limit determined in Equation 2 of this section.
The limits determined using Equation 1 or Equation 2 must be met in
accordance
[[Page 49571]]
with one of the alternatives specified in paragraphs (b)(1)(iii)(A)
through (D) of this section.
[GRAPHIC] [TIFF OMITTED] TR16AU12.009
Equation 1
Where:
ELBTEX = Unit-specific BTEX emission limit, megagrams per
year;
3.28 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 = average annual BTEX concentration of the
natural gas at the inlet to the glycol dehydration unit, ppmv.
[GRAPHIC] [TIFF OMITTED] TR16AU12.010
Where:
ELBTEX = Unit-specific BTEX emission limit, megagrams per
year;
4.66 x 10-6 = BTEX emission limit, grams BTEX/standard
cubic meter-ppmv;
Throughput = Annual average daily natural gas throughput, standard
cubic meters per day.
Ci,BTEX = average annual 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) through (iv) 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 any large glycol dehydration unit, benzene emissions are
reduced to a level less than 0.90 megagrams per year.
(iii) For each existing small glycol dehydration unit, BTEX
emissions are reduced to a level less than the limit calculated by
Equation 1 of paragraph (b)(1)(iii) of this section.
(iv) For each new small glycol dehydration unit, BTEX emissions are
reduced to a level less than the limit calculated by Equation 2 of
paragraph (b)(1)(iii) of this section.
0
15. Section 63.766 is amended by:
0
a. Adding paragraph (b)(3); and
0
b. Revising paragraph (d) to read as follows:
Sec. 63.766 Storage vessel standards.
* * * * *
(b) * * *
(3) The owner or operator shall control air emissions by connecting
the cover, through a closed-vent system that meets the conditions
specified in Sec. 63.771(c), to a process natural gas line.
* * * * *
(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 CFR part 60, subparts Kb or OOOO; or is subject to and
controlled under the requirements specified under 40 CFR part 63
subparts G or CC. Storage vessels subject to and controlled under 40
CFR part 60, subpart OOOO shall submit the periodic reports specified
in Sec. 63.775(e).
0
16. Section 63.769 is amended by:
0
a. Revising paragraph (b);
0
b. Revising paragraph (c) introductory text; and
0
c. Revising paragraph (c)(8).
The revisions 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 is subject to and controlled under the requirements specified in 40
CFR part 60, subpart OOOO. Ancillary equipment and compressors subject
to and controlled under 40 CFR part 60, subpart OOOO shall submit the
periodic reports specified in Sec. 63.775(e).
(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 that for valves
subject to Sec. 61.242-7(b) or Sec. 61.243-1, a leak is detected if
an instrument reading of 500 ppm or greater is measured. A leak
detected from a valve at a source constructed on or before August 23,
2011 shall be repaired in accordance with the schedule in Sec. 61.242-
7(d), or by October 15, 2013, whichever is later. A leak detected from
a valve at a source constructed after August 23, 2011 shall be repaired
in accordance with the schedule in Sec. 61.242-7(d), or by October 15,
2012, whichever is later.
* * * * *
[[Page 49572]]
(8) Flares, as defined in Sec. 63.761, used to comply with this
subpart shall comply with the requirements of Sec. 63.11(b).
0
17. Section 63.771 is amended by:
0
a. Revising paragraph (c)(1);
0
b. Revising the heading of paragraph (d);
0
c. Adding paragraph (d) introductory text;
0
d. Revising paragraph (d)(1)(i)(C);
0
e. Revising paragraph (d)(1)(ii);
0
f. Revising paragraph (d)(1)(iii);
0
g. Revising paragraph (d)(4)(i);
0
h. Revising paragraph (d)(5)(i);
0
i. Revising paragraph (e)(2);
0
j. Revising paragraph (e)(3) introductory text;
0
k. Revising paragraph (e)(3)(ii); and
0
l. Adding paragraph (f).
The revisions and additions 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) * * *
(C) Operates at a minimum temperature of 760 degrees C, provided
the control device has demonstrated, under Sec. 63.772(e), that
combustion zone temperature is an indicator of destruction efficiency.
* * * * *
(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 (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 meet the levels specified in paragraphs
(f)(1)(i)(A) or (B) of this section. 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.
(A) The mass content of BTEX in the gases vented to the device is
reduced as determined in accordance with the requirements of Sec.
63.772(e).
(B) The concentration of either TOC or total HAP in the exhaust
gases at the outlet of the device is reduced to a level equal to or
less than 20 parts per million by volume on a dry basis corrected to 3
percent oxygen as determined in accordance with the requirements of
Sec. 63.772(e).
(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).
(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.
[[Page 49573]]
(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.
0
18. Section 63.772 is amended by:
0
a. Revising paragraph (b) introductory text;
0
b. Revising paragraph (b)(1)(ii);
0
c. Revising paragraph (b)(2);
0
d. Revising paragraph (c)(6)(i);
0
e. Adding paragraph (d);
0
f. Revising paragraph (e) introductory text;
0
g. Revising paragraphs (e)(1)(i) through (v);
0
h. Revising paragraph (e)(2);
0
i. Revising paragraph (e)(3) introductory text;
0
j. Revising paragraph (e)(3)(i)(B);
0
k. Revising paragraph (e)(3)(iv)(C)(1);
0
l. Adding paragraphs (e)(3)(v) and (vi);
0
m. Revising paragraph (e)(4) introductory text;
0
n. Revising paragraph (e)(4)(i);
0
o. Revising paragraph (e)(5);
0
p. Revising paragraph (f) introductory text;
0
q. Revising paragraphs (f)(2) and (3);
0
r. Adding paragraphs (f)(4) through (6);
0
s. Revising paragraph (g) introductory text;
0
t. Revising paragraph (g)(1) and paragraph (g)(2) introductory text;
0
u. Revising paragraph (g)(2)(iii);
0
v. Revising paragraph (g)(3);
0
w. Adding paragraph (h); and
0
x. Adding paragraph (i).
The revisions and additions 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 (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-GLYCalcTM, Version 3.0 or
higher, and the procedures presented in the associated GRI-
GLYCalcTM Technical Reference Manual. Inputs to the model
shall be representative of actual operating conditions of the glycol
dehydration unit and may be determined using the procedures documented
in the Gas Research Institute (GRI) report entitled ``Atmospheric Rich/
Lean Method for Determining Glycol Dehydrator Emissions'' (GRI-95/
0368.1); or
(ii) The owner or operator shall determine an average mass rate of
benzene 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.
(c) * * *
(6) * * *
(i) Except as provided in paragraph (c)(6)(ii) of this section, the
detection instrument shall meet the performance criteria of Method 21
of 40 CFR part 60, appendix A, except the instrument response factor
criteria in section 3.1.2(a) of Method 21 shall be for the average
composition of the process fluid, not each individual volatile organic
compound in the stream. For process streams that contain nitrogen, air,
or other inert gases that are not organic hazardous air pollutants or
volatile organic compounds, the average stream response factor shall be
calculated on an inert-free basis.
* * * * *
(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-GLYCalcTM, Version 3.0 or
higher, and the procedures presented in the associated GRI-
GLYCalcTM Technical Reference Manual. Inputs to the model
shall be representative of actual operating conditions of the glycol
dehydration unit and 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-GLYCalcTM, 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 to control emissions from a glycol dehydration unit process vent.
Flares shall meet the provisions in paragraph (e)(2) of this section.
As an alternative to conducting a performance test under this section
for combustion control devices, a control device that can be
[[Page 49574]]
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. 63.771(d)(1)(i)(B), or
the BTEX emission limit specified in Sec. 63.765(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, ASTM D6522-00 (Reapproved 2005), or ANSI/ASME PTC 19.10-
1981, Part 10 (manual portion only) (incorporated by reference as
specified in Sec. 63.14) 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. 63.765(b)(1)(iii) the owner or operator shall use one of the
following methods: Method 18, 40 CFR part 60, appendix A; ASTM D6420-99
(Reapproved 2004), as specified in Sec. 63.772(a)(1)(ii) (incorporated
by reference as specified in Sec. 63.14); 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] TR16AU12.011
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
(Reapproved 2004) (incorporated by reference as specified in Sec.
63.14) 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 (i.e., control devices
installed on or before August 23, 2011) at major sources shall be
conducted no later than October 15, 2015. If the owner or operator of
an existing combustion control device at a 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 October 15, 2015. 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 demonstrating during the
performance test under Sec. 63.772(e) that combustion
[[Page 49575]]
zone temperature is an indicator of destruction efficiency and operates
at a minimum temperature of 760 degrees C.
(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 (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-GLYCalcTM, 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 flowrate 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
flowrate, 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) or under the performance test conducted under Sec.
63.772(e), as applicable.
(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
compliance dates specified in
[[Page 49576]]
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
paragraph (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. During the first 5 minutes,
incrementally 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, incrementally 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. During the first 5 minutes,
incrementally 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,
incrementally 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. During the first 5 minutes,
incrementally ramp the firing rate to 30 percent of the maximum design
rate. Hold at 30 percent for 5 minutes. In the 10-15 minute time range,
incrementally 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 (h)(8)(iii) of this section.
(4) Inlet gas testing shall be conducted as specified in paragraphs
(h)(4)(i) through (iii) of this section.
(i) The inlet gas flow metering system shall be located in
accordance with Method 2A, 40 CFR part 60, appendix A-1, (or other
approved procedure) to measure inlet gas flowrate at the control device
inlet location. The fitting for filling inlet gas sample containers
shall be located a minimum of 8 pipe diameters upstream of any inlet
gas flow monitoring meter.
(ii) Inlet gas flowrate 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 inlet gas pressure and temperature at 5-
minute intervals throughout each 60-minute THC test.
(iii) Inlet gas 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 gas sampling location, securely connect a
Silonite-coated stainless steel evacuated canister fitted with a flow
controller sufficient to fill the canister over a 3 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 each THC
run.
(2) Fill one canister across the three test runs for each THC test
such that one composite fuel sample exists for each test condition.
(3) Label the canisters individually and record on a chain of
custody form.
(B) Each inlet gas 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 (Reapproved 2010) (incorporated
by reference as specified in Sec. 63.14).
(2) Hydrogen (H2), carbon monoxide (CO), carbon dioxide
(CO2), nitrogen (N2), oxygen (O2)
using ASTM D1945-03 (Reapproved 2010) (incorporated by reference as
specified in Sec. 63.14).
(3) Higher heating value using ASTM D3588-98 (Reapproved 2003) or
ASTM D4891-89 (Reapproved 2006) (incorporated by reference as specified
in Sec. 63.14).
(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) Flowrate 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 or other pressure
measurement device shall be used to obtain an accurate flow profile.
(ii) Molecular weight shall be determined as specified in
paragraphs (h)(4)(iii)(B) and (h)(5)(ii)(A) and (B) of this section.
(A) An integrated bag sample shall be collected during the Method
4, 40 CFR
[[Page 49577]]
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 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, or ASTM D6522-00 (Reapproved 2005), (incorporated
by reference as specified in Sec. 63.14). 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.
(v) Excess air shall be determined using resultant data from the
EPA Method 3C tests and EPA Method 3B, 40 CFR part 60, Appendix A,
equation 3B-1 or ANSI/ASME PTC 19.10, 1981-Part 10 (manual portion
only) (incorporated by reference as specified in Sec. 63.14).
(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 each
test.
(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.
(D) Excess combustion air shall be equal to or greater than 150
percent.
(ii) The manufacturer shall determine a maximum inlet gas flowrate
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 95.0 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 flowrate.
(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 flowrate.
(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 flowrate shall meet the range specified by the
manufacturer. Flowrate shall be calculated 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
[[Page 49578]]
to exceed a total of 2 minutes during any hour. A visible emissions
test using Method 22, 40 CFR part 60, Appendix A, shall be performed
each calendar quarter. The observation period shall be 1 hour and shall
be conducted according to EPA Method 22, 40 CFR part 60, Appendix A.
(4) Compliance with the operating parameter limit is achieved when
the following criteria are met:
(i) The inlet gas flowrate 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 section the duration of visible emissions does not
exceed a total of 2 minutes during the observation period. Devices
failing the visible emissions test shall follow manufacturers repair
instructions, if available, or best combustion engineering practice as
outlined in the unit inspection and maintenance plan, to return the
unit to compliant operation. All repairs and maintenance activities for
each unit shall be recorded in a maintenance and repair log and shall
be available on site for inspection.
(iv) Following return to operation from maintenance or repair
activity, each device must pass a Method 22 visual observation as
described in paragraph (i)(3) of this section.
0
19. Section 63.773 is amended by:
0
a. Adding paragraph (b);
0
b. Revising paragraph (d)(1) introductory text;
0
c. Revising paragraph (d)(1)(ii) and adding paragraphs (d)(1)(iii) and
(iv);
0
d. Revising paragraph (d)(2);
0
e. Revising paragraph (d)(3)(i)(A);
0
f. Revising paragraph (d)(3)(i)(D);
0
g. Revising paragraph (d)(3)(i)(G);
0
h. Adding paragraph (d)(3)(i)(H);
0
i. Revising paragraph (d)(4);
0
j. Revising paragraph (d)(5)(i);
0
k. Revising paragraphs (d)(5)(ii)(A) through (C);
0
l. Revising paragraph (d)(6) introductory text;
0
m. Revising paragraphs (d)(6)(ii) and (iii);
0
n. Adding paragraph (d)(6)(vi);
0
o. Revising paragraph (d)(7); and
0
p. Removing paragraphs (d)(8) and (9).
The revisions and additions 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 (7) 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 (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) An owner or operator is exempt from the monitoring requirements
specified in paragraphs (d)(3) through (7) of this section for the
following types of control devices:
(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 2 percent of the
temperature being monitored in [deg]C, or 2.5 [deg]C,
whichever value is greater. The temperature sensor shall be installed
at a location representative of the combustion zone temperature.
* * * * *
(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 2 percent of the
temperature being monitored in [deg]C, or 2.5 [deg]C,
whichever value is greater. The temperature sensor shall be installed
at a location representative of the combustion zone temperature.
* * * * *
(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) and shall be based on the total carbon working capacity of
the control device and source operating schedule.
[[Page 49579]]
(H) For a control device model whose model is tested under Sec.
63.772(h):
(1) The owner or operator shall determine actual average inlet
waste gas flowrate using the model GRI-GLYCalc \TM\, Version 3.0 or
higher, ProMax, or AspenTech HYSYS. Inputs to the models shall be
representative of actual operating conditions of the controlled unit.
The determination shall be performed to coincide with the visible
emissions test under Sec. 63.772(i)(3);
(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. 63.771(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 flowrate 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 of both.
(B) If the owner or operator uses a control device design analysis
in accordance with the requirements of Sec. 63.772(e)(4)(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) 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 (vi)
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 (vi) 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. 63.771(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(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 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 flowrate exceeds the maximum established during
the test conducted under Sec. 63.772(h).
(B) Failure of the quarterly visible emissions test conducted under
Sec. 63.772(i)(3) occurs.
(7) For each excursion, the owner or operator shall be deemed to
have failed to have applied control in a manner that achieves the
required operating parameter limits. Failure to achieve the required
operating parameter limits is a violation of this standard.
* * * * *
0
20. Section 63.774 is amended by:
0
a. Revising paragraph (b)(3) introductory text;
0
b. Removing and reserving paragraph (b)(3)(ii);
0
c. Revising paragraph (b)(4)(ii) introductory text;
0
d. Adding paragraph (b)(4)(ii)(C);
0
e. Revising paragraph (b)(4)(iii);
0
f. Adding paragraph (b)(7)(ix); and
0
g. Adding paragraphs (g) through (i).
The revisions and additions read as follows:
Sec. 63.774 Recordkeeping requirements.
* * * * *
(b) * * *
(3) Records specified in Sec. 63.10(c) for each monitoring system
operated by the
[[Page 49580]]
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 (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.
* * * * *
(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 a control device whose model is tested under Sec.
63.772(h), the records required in paragraph (h) of this section.
(iii) Hourly records of the times and durations of all periods when
the vent stream is diverted from the control device or the device is
not operating.
* * * * *
(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(j), 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 calculations 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.
0
21. Section 63.775 is amended by:
0
a. Revising paragraph (b)(1);
0
b. Revising paragraph (b)(6);
0
c. Removing and reserving paragraph (b)(7);
0
d. Revising paragraph (c)(1);
0
e. Revising paragraph (c)(6);
0
f. Revising paragraph (c)(7)(i);
0
g. Revising paragraph (d)(1)(i);
0
h. Revising paragraph (d)(1)(ii) introductory text;
0
i. Revising paragraph (d)(5)(ii);
0
j. Adding paragraph (d)(5)(iv);
0
k. Revising paragraph (d)(11);
0
l. Adding paragraphs (d)(13) and (d)(14);
0
m. Revising paragraphs (e)(2) introductory text, (e)(2)(ii)(B) and (C);
0
n. Adding paragraphs (e)(2)(ii)(E) and (F);
0
o. Adding paragraphs (e)(2)(xi) through (xiv); and
0
p. Adding paragraph (g).
The revisions and additions 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 (b)(1)(ii) of this
section, 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 October 15,
2013, whichever is later. An affected source identified under Sec.
63.760(f)(7) or (9) that plans to be an area source by October 15,
2015, 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.
* * * * *
(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 email 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 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
[[Page 49581]]
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 email to [email protected] unless the test
results for that model of combustion control device are posted at the
following Web site: epa.gov/airquality/oilandgas/.
* * * * *
(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 the model of control device was tested by the
manufacturer.
(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 (ix) 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 flowrate
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, repairs affected to the unit, and date the unit was returned
to service.
* * * * *
(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).
(xiv) Certification by a responsible official of truth, accuracy,
and completeness. This certification shall state that, based on
information and belief formed after reasonable inquiry, the statements
and information in the document are true, accurate, and complete.
* * * * *
(g) Electronic reporting. (1) Within 60 days after the date of
completing each performance test (defined in Sec. 63.2) as required by
this subpart you must submit the results of the performance tests
required by this subpart to EPA's WebFIRE database by using the
Compliance and Emissions Data Reporting Interface (CEDRI) that is
accessed through EPA's Central Data Exchange (CDX) (www.epa.gov/cdx).
Performance test data must be submitted in the file format generated
through use of EPA's Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/index.html). Only data collected using test
methods on the ERT Web site are subject to this requirement for
submitting reports electronically to WebFIRE. Owners or operators who
claim that some of the information being submitted for performance
tests is confidential business information (CBI) must submit a complete
ERT file including information claimed to be CBI on a compact disk or
other commonly used electronic storage media (including, but not
limited to, flash drives) to EPA. The electronic media must be clearly
marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention:
WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703.
The same ERT file with the CBI omitted must be submitted to EPA via CDX
as described earlier in this paragraph. At the discretion of the
delegated authority, you must also submit these reports, including the
confidential business information, to the delegated authority in the
format specified by the delegated authority.
(2) All reports required by this subpart not subject to the
requirements in paragraph (g)(1) of this section must be sent to the
Administrator at the appropriate address listed in Sec. 63.13. The
Administrator or the delegated authority may request a report in any
form suitable for the specific case (e.g., by commonly used electronic
media such as Excel spreadsheet, on CD or hard copy). The Administrator
retains the right to require submittal of reports subject to paragraph
(g)(1) of this section in paper format.
0
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 49582]]
Table 2 to Subpart HH of Part 63--Applicability of 40 CFR Part 63
General Provisions to Subpart HH
------------------------------------------------------------------------
Applicable to
General provisions reference 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 No.................. Section reserved.
(a)(9).
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 Yes. ....................
(a)(2).
Sec. 63.4(a)(3) through No.................. Section reserved.
(a)(5).
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 No.................. Section reserved.
(c)(4).
Sec. 63.6(c)(5)........... Yes. ....................
Sec. 63.6(d).............. No.................. Section reserved.
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)(1)........... No. ....................
Sec. 63.6(h)(2) through Yes. ....................
(h)(9).
Sec. 63.6(i)(1) through Yes. ....................
(i)(14).
Sec. 63.6(i)(15).......... No.................. Section reserved.
Sec. 63.6(i)(16).......... Yes. ....................
Sec. 63.6(j).............. Yes. ....................
[[Page 49583]]
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(a)(4)........... 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)...... No. ....................
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 Yes. ....................
(c)(8).
Sec. 63.8(d)(1)........... Yes.
Sec. 63.8(d)(2)........... 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 Yes. ....................
(f)(5).
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).............. Yes. ....................
Sec. 63.9(g).............. Yes. ....................
Sec. 63.9(h)(1) through Yes................. Area sources located
(h)(3). 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 Yes. ....................
(h)(6).
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 (1) occurrence
and duration and
(2) actions taken
during
malfunctions.
Sec. 63.10(b)(2)(iii)..... Yes. ....................
Sec. 63.10(b)(2)(iv) No. ....................
through (b)(2)(v).
Sec. 63.10(b)(2)(vi) Yes. ....................
through (b)(2)(xiv).
[[Page 49584]]
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 No.................. Sections reserved.
(c)(4).
Sec. 63.10(c)(5) through Yes. ....................
(c)(8).
Sec. 63.10(c)(9).......... No.................. Section reserved.
Sec. 63.10(c)(10) through No.................. See Sec. 63.774(g)
(11). for recordkeeping
of malfunctions.
Sec. 63.10(c)(12) through Yes. ....................
(14).
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.
Sec. 63.10(e)(3)(i)(D).... Yes................. Section reserved.
Sec. 63.10(e)(3)(ii) Yes.
through (viii).
Sec. 63.10(e)(4).......... Yes. ....................
Sec. 63.10(f)............. Yes. ....................
Sec. 63.11(a) and (b)..... Yes. ....................
Sec. 63.11(c), (d), and Yes. ....................
(e).
Sec. 63.12(a) through (c). Yes. ....................
Sec. 63.13(a) through (c). Yes. ....................
Sec. 63.14(a) through (q). Yes. ....................
Sec. 63.15(a) and (b)..... Yes. ....................
Sec. 63.16................ Yes. ....................
------------------------------------------------------------------------
Subpart HHH--[Amended]
0
23. Section 63.1270 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Revising paragraph (a)(4);
0
c. Revising paragraph (b);
0
d. Revising paragraphs (d)(1) and (2); and
0
e. Adding paragraphs (d)(3) and (4).
The revisions and additions 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
[[Page 49585]]
operational design consistent with the definition of potential to emit
in Sec. 63.2.
(b) The affected source is each new and existing glycol dehydration
unit specified in paragraphs (b)(1) through (3) of this section.
(1) Each large glycol dehydration unit;
(2) Each small glycol dehydration unit for which construction
commenced on or before August 23, 2011, is an existing small glycol
dehydration unit.
(3) Each small glycol dehydration unit for which construction
commenced after August 23, 2011, is a new small glycol dehydration
unit.
* * * * *
(d) * * *
(1) Except as specified in paragraphs (d)(3) through (4) of this
section, the owner or operator of an affected source, the construction
or reconstruction of which commenced before February 6, 1998, shall
achieve compliance with this provisions of the subpart no later than
June 17, 2002 except as provided for in Sec. 63.6(i). The owner or
operator of an area source, the construction or reconstruction of which
commenced before February 6, 1998, that increases its emissions of (or
its potential to emit) HAP such that the source becomes a major source
that is subject to this subpart shall comply with this subpart 3 years
after becoming a major source.
(2) Except as specified in paragraphs (d)(3) through (4) 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 October
15, 2015, 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 October 15, 2012, whichever is later.
* * * * *
0
24. Section 63.1271 is amended by:
0
a. Adding, in alphabetical order, definitions for the terms
``affirmative defense,'' ``BTEX,'' ``flare,'' ``large glycol
dehydration units,'' ``responsible official'' and ``small glycol
dehydration units;'' and
0
b. Revising the definition for ``glycol dehydration unit baseline
operations.''
The additions and revision 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). A glycol dehydration unit complying with
the 0.9 Mg/yr control option under 63.1275(b)(1)(ii) is considered to
be a large dehydrator.
* * * * *
Responsible official means one of the following:
(1) For a corporation: A president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business
function, or any other person who performs similar policy or decision-
making functions for the corporation, or a duly authorized
representative of such person if the representative is responsible for
the overall operation of one or more manufacturing, production, or
operating facilities applying for or subject to a permit and either:
(i) The facilities employ more than 250 persons or have gross
annual sales or expenditures exceeding $25 million (in second quarter
1980 dollars); or
(ii) The delegation of authority to such representatives is
approved in advance by the permitting authority;
(2) For a partnership or sole proprietorship: A general partner or
the proprietor, respectively;
(3) For a municipality, State, Federal, or other public agency:
Either a principal executive officer or ranking elected official. For
the purposes of this part, a principal executive officer of a Federal
agency includes the chief executive officer having responsibility for
the overall operations of a principal geographic unit of the agency
(e.g., a Regional Administrator of EPA); or
(4) For affected sources:
(i) The designated representative in so far as actions, standards,
requirements, or prohibitions under title IV of the Act or the
regulations promulgated thereunder are concerned; and
(ii) The designated representative for any other purposes under
part 70.
* * * * *
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).
* * * * *
0
25. Section 63.1272 is revised to read as follows:
Sec. 63.1272 Affirmative defense for violations of emission standards
during malfunction.
(a) The provisions set forth in this subpart shall apply at all
times.
(b) [Reserved]
(c) [Reserved]
(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 violations of such standards that are caused by
malfunction, as defined at Sec. 63.2. 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.
[[Page 49586]]
(1) To establish the affirmative defense in any action to enforce
such a standard, you must timely meet the reporting requirements in
paragraph (d)(2) of this section, and must prove by a preponderance of
evidence that:
(i) The violation:
(A) Was caused by a sudden, infrequent, and unavoidable failure of
air pollution control 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) Was not part of a recurring pattern indicative of inadequate
design, operation, or maintenance; and
(ii) Repairs were made as expeditiously as possible when a
violation occurred. Off-shift and overtime labor were used, to the
extent practicable to make these repairs; and
(iii) The frequency, amount and duration of the violation
(including any bypass) were minimized to the maximum extent
practicable; and
(iv) If the violation 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
violation 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 violation 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, the purpose
of which is to determine, correct, and eliminate the primary causes of
the malfunction and the violation resulting from the malfunction event
at issue. The analysis shall also specify, using best monitoring
methods and engineering judgment, the amount of any emissions that were
the result of the malfunction.
(2) Report. The owner or operator seeking to assert an affirmative
defense shall submit a written report to the Administrator with all
necessary supporting documentation, that it has met the requirements
set forth in paragraph (d)(1) of this section. This affirmative defense
report shall be included in the first periodic compliance, deviation
report or excess emission report otherwise required after the initial
occurrence of the violation of the relevant standard (which may be the
end of any applicable averaging period). If such compliance, deviation
report or excess emission report is due less than 45 days after the
initial occurrence of the violation, the affirmative defense report may
be included in the second compliance, deviation report or excess
emission report due after the initial occurrence of the violation of
the relevant standard.
0
26. Section 63.1274 is amended by:
0
a. Revising paragraph (c) introductory text;
0
b. Removing and reserving paragraph (d);
0
c. Revising paragraph (g); and
0
d. Adding paragraph (h).
The revisions and addition 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.
0
27. Section 63.1275 is amended by:
0
a. Revising paragraph (a);
0
b. Revising paragraph (b)(1);
0
c. Revising paragraph (c)(2); and
0
d. Revising paragraph (c)(3).
The revisions 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
(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) The owner or operator of a large glycol dehydration unit shall
connect the process vent to a control device or a combination of
control devices through a closed-vent system and the outlet benzene
emissions from the control device(s) shall be less than 0.90 megagrams
per year. The closed-vent system shall be designed and operated in
accordance with the requirements of Sec. 63.1281(c). The control
device(s) shall be designed and operated in accordance with the
requirements of Sec. 63.1281(d), except that the performance
requirements specified in Sec. 63.1281(d)(1)(i) and (ii) do not apply.
(iii) You must limit BTEX emissions from each existing small glycol
dehydration unit, as defined in Sec. 63.1271, to the limit determined
in Equation 1 of this section. You must limit BTEX emissions from each
new small glycol dehydration unit process vent, as defined in Sec.
63.1271, to the limit determined in Equation 2 of this section. The
limits determined using Equation 1 or Equation 2, of this section, must
be met in accordance with one of the alternatives specified in
paragraphs (b)(1)(iii)(A) through (D) of this section.
[[Page 49587]]
[GRAPHIC] [TIFF OMITTED] TR16AU12.012
Where:
ELBTEX = Unit-specific BTEX emission limit, megagrams per
year;
3.10 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 = Annual average BTEX concentration of the
natural gas at the inlet to the glycol dehydration unit, ppmv.
[GRAPHIC] [TIFF OMITTED] TR16AU12.013
Where:
ELBTEX = Unit-specific BTEX emission limit, megagrams per
year;
5.44 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 = Annual average 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) through (iv) 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 any large glycol dehydration unit, benzene emissions are
reduced to a level less than 0.90 megagrams per year.
(iii) For each existing small glycol dehydration unit, BTEX
emissions are reduced to a level less than the limit calculated in
Equation 1 of paragraph (b)(1)(iii) of this section.
(iv) For each new small glycol dehydration unit, BTEX emissions are
reduced to a level less than the limit calculated in Equation 2 of
paragraph (b)(1)(iii) of this section.
0
28. Section 63.1281 is amended by:
0
a. Revising paragraph (c)(1);
0
b. Revising the heading of paragraph (d).
0
c. Adding paragraph (d) introductory text;
0
d. Revising paragraph (d)(1)(i)(C);
0
e. Revising paragraphs (d)(1)(ii) and (iii);
0
f. Revising paragraph (d)(4)(i);
0
g. Revising paragraph (d)(5)(i);
0
h. Revising paragraph (e)(2);
0
i. Revising paragraph (e)(3) introductory text;
0
j. Revising paragraph (e)(3)(ii); and
0
k. Adding paragraph (f).
The revisions and additions 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) * * *
(C) Operates at a minimum temperature of 760 degrees C, provided
the control device has demonstrated, under Sec. 63.1282(d), that
combustion zone temperature is an indicator of destruction efficiency.
* * * * *
(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
[[Page 49588]]
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 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 meet the levels specified in paragraphs
(f)(1)(i)(A) or (B) of this section. 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.
(A) The mass content of BTEX in the gases vented to the device is
reduced as determined in accordance with the requirements of Sec.
63.1282(d).
(B) The concentration of either TOC or total HAP in the exhaust
gases at the outlet of the device is reduced to a level equal to or
less than 20 parts per million by volume on a dry basis corrected to 3
percent oxygen as determined in accordance with the requirements of
Sec. 63.1282(e).
(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).
(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.
0
29. Section 63.1282 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Revising paragraph (a)(1)(ii);
0
c. Revising paragraph (a)(2);
0
d. Revising paragraph (b)(6)(i);
0
e. Adding paragraph (c);
0
f. Revising paragraph (d) introductory text;
0
g. Revising paragraphs (d)(1)(i) through (v);
0
h. Revising paragraph (d)(2);
0
i. Revising paragraph (d)(3) introductory text;
0
j. Revising paragraph (d)(3)(i)(B);
0
k. Revising paragraph (d)(3)(iii) introductory text;
0
l. Revising paragraph (d)(3)(iv) introductory text;
0
m. Revising paragraph (d)(3)(iv)(C)(1);
0
n. Adding paragraphs (d)(3)(v) and (vi);
0
o. Revising paragraph (d)(4) introductory text;
0
p. Revising paragraph (d)(4)(i);
0
q. Revising paragraph (d)(5);
0
r. Revising paragraph (e) introductory text;
0
s. Revising paragraphs (e)(2) and (3);
0
t. Adding paragraphs (e)(4) through (e)(6);
0
u. Revising paragraph (f) introductory text;
0
v. Revising paragraph (f)(1);
0
w. Revising paragraph (f)(2) introductory text;
0
x. Revising paragraph (f)(2)(iii) introductory text, (f)(2)(iii)(A) and
(f)(2)(iii)(B);
0
y. Revising paragraph (f)(3); and
0
z. Adding paragraphs (g) and (h).
The revisions and additions 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 (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
[[Page 49589]]
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 ASTM D6420-99 (Reapproved 2004) (incorporated by
reference as specified in Sec. 63.14), as specified in Sec.
63.772(a)(1)(ii); or an equivalent method; and averaging the results of
the three runs. Annual emissions in kilograms per year shall be
determined by multiplying the mass rate by the number of hours the unit
is operated per year. This result shall be converted to megagrams per
year.
(b) * * *
(6) * * *
(i) Except as provided in paragraph (b)(6)(ii) of this section, the
detection instrument shall meet the performance criteria of Method 21
of 40 CFR part 60, appendix A, except the instrument response factor
criteria in section 3.1.2(a) of Method 21 shall be for the average
composition of the process fluid not each individual volatile organic
compound in the stream. For process streams that contain nitrogen, air,
or other inert gases that are not organic HAP or VOC, the average
stream response factor shall be calculated on an inert-free basis.
* * * * *
(c) Test procedures and compliance demonstrations for small glycol
dehydration units. This paragraph (c) 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 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.
Flares shall meet the provisions in paragraph (d)(2) of this section.
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
[[Page 49590]]
shall be located at the outlet of the combustion device.
* * * * *
(iii) To determine compliance with the control device percent
reduction performance requirement in Sec. 63.1281(d)(1)(i)(A),
63.1281(d)(1)(ii), or 63.1281(e)(3)(ii), the owner or operator shall
use either Method 18, 40 CFR part 60, appendix A, or Method 25A, 40 CFR
part 60, appendix A; or ASTM D6420-99 (incorporated by reference as
specified in Sec. 63.14), as specified in Sec. 63.772(a)(1)(ii);
alternatively, any other method or data that have been validated
according to the applicable procedures in Method 301 of appendix A of
this part may be used. The following procedures shall be used to
calculate the percentage of reduction:
* * * * *
(iv) To determine compliance with the enclosed combustion device
total HAP concentration limit specified in Sec. 63.1281(d)(1)(i)(B),
the owner or operator shall use either Method 18, 40 CFR part 60,
appendix A; or Method 25A, 40 CFR part 60, appendix A; or ASTM D6420-99
(Reapproved 2004) (incorporated by reference as specified in Sec.
63.14), as specified in Sec. 63.772(a)(1)(ii), to measure either TOC
(minus methane and ethane) or total HAP. Alternatively, any other
method or data that have been validated according to Method 301 of
appendix A of this part, may be used. The following procedures shall be
used to calculate parts per million by volume concentration, corrected
to 3 percent oxygen:
* * * * *
(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, ASTM D6522-00 (Reapproved 2005), or ANSI/ASME PTC 19.10-
1981, Part 10 (manual portion only) (incorporated by reference as
specified in Sec. 63.14) 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. 63.1275(b)(1)(iii) the owner or operator shall use one of the
following methods: Method 18, 40 CFR part 60, appendix A; ASTM D6420-99
(Reapproved 2004) (incorporated by reference as specified in Sec.
63.14), 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] TR16AU12.014
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
(Reapproved 2004) (incorporated by reference as specified in Sec.
63.14) 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 (i.e., control devices
installed on or before August 23, 2011) at major sources shall be
conducted no later than October 15, 2015. If the owner or operator of
an existing combustion control device at a 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 October 15, 2015. 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 demonstrating during the
performance test under Sec. 63.1282(d) that combustion zone
temperature is an indicator of destruction efficiency and operates at a
minimum temperature of 760 degrees C.
(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 (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.
* * * * *
[[Page 49591]]
(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) or under the performance test
conducted under Sec. 63.1282(d), as applicable.
(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.
* * * * *
(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 or is equal to or greater than
the minimum percent reduction necessary to meet the BTEX emission limit
as determined in paragraph (f)(1) of this section.
* * * * *
(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.
[[Page 49592]]
(g) Performance testing for combustion control devices--
manufacturers' performance test.
(1) This paragraph (g) 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. During the first 5 minutes,
incrementally 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, incrementally 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. During the first 5 minutes,
incrementally 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,
incrementally 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. During the first 5 minutes,
incrementally ramp the firing rate to 30 percent of the maximum design
rate. Hold at 30 percent for 5 minutes. In the 10-15 minute time range,
incrementally 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 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 inlet gas flow metering system shall be located in
accordance with Method 2A, 40 CFR part 60, appendix A-1, (or other
approved procedure) to measure inlet gas flowrate 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 gas flow
monitoring meter.
(ii) Inlet gas flowrate 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 inlet gas pressure and temperature at 5-
minute intervals throughout each 60-minute THC test.
(iii) Inlet gas sampling shall be conducted in accordance with the
criteria in paragraphs (g)(4)(iii)(A) and (B) of this section.
(A) At the inlet gas sampling location, securely connect a
Silonite-coated stainless steel evacuated canister fitted with a flow
controller sufficient to fill the canister over a 3 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 each THC
test run.
(2) Fill one canister across the three test runs for each THC test
such that one composite fuel sample exists for each test condition.
(3) Label the canisters individually and record on a chain of
custody form.
(B) Each inlet gas 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 (Reapproved 2010) (incorporated
by reference as specified in Sec. 63.14).
(2) Hydrogen (H2), carbon monoxide (CO), carbon dioxide
(CO2), nitrogen (N2), oxygen (O2)
using ASTM D1945-03 (Reapproved 2010) (incorporated by reference as
specified in Sec. 63.14).
(3) Higher heating value using ASTM D3588-98 (Reapproved 2003) or
ASTM D4891-89 (Reapproved 2006) (incorporated by reference as specified
in Sec. 63.14).
(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 the exit or any other flow disturbance. A minimum of two
sample ports shall be used.
(B) Flowrate 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 or other pressure
measurement device 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 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
[[Page 49593]]
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 or ASTM D6522-00 (Reapproved 2005) (incorporated by
reference as specified in Sec. 63.14). 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.
(v) Excess air shall be determined using resultant data from the
EPA Method 3C tests and EPA Method 3B, 40 CFR part 60, Appendix A,
equation 3B-1 or ANSI/ASME PTC 19.10-1981, Part 10 (manual portion
only) (incorporated by reference as specified in Sec. 63.14).
(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
test run.
(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.
(D) Excess combustion air shall be equal to or greater than 150
percent.
(ii) The manufacturer shall determine a maximum inlet gas flowrate
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 95.0 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 flowrate.
(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 flowrate.
(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:
(1) The inlet gas flowrate shall meet the range specified by the
manufacturer. Flowrate shall be calculated 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 2 minutes during any hour. A visible
emissions test using Method 22, 40 CFR part 60, Appendix A, shall be
performed each calendar quarter. The observation period shall be 1 hour
and shall be conducted according to EPA Method 22, 40 CFR part 60,
Appendix A.
(4) Compliance with the operating parameter limit is achieved when
the following criteria are met:
(i) The inlet gas flowrate 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 2 minutes during the observation period. Devices
failing the visible emissions test shall follow manufacturers repair
instructions, if available, or best combustion engineering practice as
outlined in the unit inspection and maintenance plan, to return the
unit to compliant operation. All repairs and maintenance activities for
each unit shall be recorded in a maintenance and repair log and shall
be available on site for inspection.
(iv) Following return to operation from maintenance or repair
activity, each device must pass a Method 22 visual observation as
described in paragraph (h)(3) of this section.
[[Page 49594]]
0
30. Section 63.1283 is amended by:
0
a. Adding paragraph (b);
0
b. Revising paragraph (d)(1) introductory text;
0
c. Revising paragraph (d)(1)(ii) and adding paragraphs (d)(1)(iii) and
(iv);
0
d. Revising paragraph (d)(2);
0
e. Revising paragraph (d)(3)(i)(A);
0
f. Revising paragraph (d)(3)(i)(D);
0
g. Revising paragraph (d)(3)(i)(G);
0
h. Adding paragraph (d)(3)(i)(H);
0
i. Revising paragraph (d)(4);
0
j. Revising paragraph (d)(5)(i);
0
k. Revising paragraphs (d)(5)(ii)(A) through (C);
0
l. Revising paragraph (d)(6) introductory text;
0
m. Revising paragraph (d)(6)(ii);
0
n. Adding paragraph (d)(6)(v);
0
o. Revising paragraph (d)(7); and
0
p. Removing and reserving paragraph (d)(8).
The additions and revisions 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 (7) 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) An owner or operator is exempted from the monitoring
requirements specified in paragraphs (d)(3) through (7) of this section
for the following types of control devices:
(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 2 percent of the
temperature being monitored in [deg]C, or 2.5 [deg]C,
whichever value is greater. The temperature sensor shall be installed
at a location representative of the combustion zone temperature.
* * * * *
(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 2 percent of the
temperature being monitored in [deg]C, or 2.5 [deg]C,
whichever value is greater. The temperature sensor shall be installed
at a location representative of the combustion zone temperature.
* * * * *
(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) The owner or operator shall determine actual average inlet
waste gas flowrate using the model GRI-GLYCalc\TM\, Version 3.0 or
higher, ProMax, or AspenTech HYSYS. Inputs to the models shall be
representative of actual operating conditions of the controlled unit.
The determination shall be performed to coincide with the visible
emissions test under Sec. 63.1282(h)(3);
(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
[[Page 49595]]
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 flowrate 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-GLYCalc\TM\, Version 3.0 or higher, to generate a condenser
performance curve.
(6) An excursion for a given control device is determined to have
occurred when the monitoring data or lack of monitoring data result in
any one of the criteria specified in paragraphs (d)(6)(i) through
(d)(6)(v) of this section being met. When multiple operating parameters
are monitored for the same control device and during the same operating
day, and more than one of these operating parameters meets an excursion
criterion specified in paragraphs (d)(6)(i) through (d)(6)(v) of this
section, then a single excursion is determined to have occurred for the
control device for that operating day.
* * * * *
(ii) For sources meeting Sec. 63.1281(d)(1)(ii), an excursion
occurs when average condenser efficiency calculated according to the
requirements specified in Sec. 63.1282(f)(2)(iii) is less than 95.0
percent, as specified in Sec. 63.1282(f)(3). 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 flowrate exceeds the maximum established during
the test conducted under Sec. 63.1282(g).
(B) Failure of the quarterly visible emissions test conducted under
Sec. 63.1282(h)(3) occurs.
(7) For each excursion, the owner or operator shall be deemed to
have failed to have applied control in a manner that achieves the
required operating parameter limits. Failure to achieve the required
operating parameter limits is a violation of this standard.
(8) [Reserved]
* * * * *
0
31. Section 63.1284 is amended by:
0
a. Revising paragraph (b)(3) introductory text;
0
b. Removing and reserving paragraph (b)(3)(ii);
0
c. Revising paragraph (b)(4)(ii);
0
d. Revising paragraph (b)(4)(iii);
0
e. Adding paragraph (b)(7)(ix); and
0
f. Adding paragraphs (f), (g) and (h).
The revisions and additions 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.
(iii) Hourly records of the times and durations of all periods when
the vent stream is diverted from the control device or the device is
not operating.
* * * * *
(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
[[Page 49596]]
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(h), 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 calculations 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.
0
32. Section 63.1285 is amended by:
0
a. Revising paragraph (b)(1);
0
b. Revising paragraph (b)(6);
0
c. Removing paragraph (b)(7);
0
d. Revising paragraph (d) introductory text;
0
e. Revising paragraph (d)(1) introductory text;
0
f. Revising paragraph (d)(1)(i);
0
g. Revising paragraph (d)(1)(ii) introductory text;
0
h. Revising paragraph (d)(2) introductory text;
0
i. Revising paragraph (d)(4) introductory text;
0
j. Revising paragraph (d)(4)(ii);
0
k. Adding paragraph (d)(4)(iv);
0
l. Revising paragraph (d)(10);
0
m. Adding paragraphs (d)(11) and (d)(12);
0
n. Revising paragraph (e)(2) introductory text;
0
o. Revising paragraph (e)(2)(ii)(B);
0
p. Adding paragraphs (e)(2)(ii)(D) and (E);
0
q. Adding paragraphs (e)(2)(x) through (xiii); and
0
r. Adding paragraph (g).
The revisions and additions 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 October 15, 2013,
whichever is later. An affected source identified under Sec.
63.1270(d)(3) that plans to be an area source by October 15, 2015,
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. 63.1274(h), including actions taken
to correct a malfunction.
* * * * *
(d) Each owner or operator of a source subject to this subpart
shall submit a Notification of Compliance Status Report as required
under Sec. 63.9(h) within 180 days after the compliance date specified
in Sec. 63.1270(d). In addition to the information required under
Sec. 63.9(h), the Notification of Compliance Status Report shall
include the information specified in paragraphs (d)(1) through (12) of
this section. This information may be submitted in an operating permit
application, in an amendment to an operating permit application, in a
separate submittal, or in any combination of the three. If all of the
information required under this paragraph have been submitted at any
time prior to 180 days after the applicable compliance dates specified
in Sec. 63.1270(d), a separate Notification of Compliance Status
Report is not required. If an owner or operator submits the information
specified in paragraphs (d)(1) through (12) of this section at
different times, and/or different submittals, subsequent submittals may
refer to previous submittals instead of duplicating and resubmitting
the previously submitted information.
(1) If a closed-vent system and a control device other than a flare
are used to comply with Sec. 63.1274, the owner or operator shall
submit 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 email to [email protected] unless the test
results for that model of combustion control device are posted at the
following Web site: epa.gov/airquality/oilandgas/.
* * * * *
(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) For each control device other than a flare used to meet the
requirements of Sec. 63.1274, the owner or operator shall submit the
information specified in paragraphs (d)(4)(i) through (iv) of this
section for each operating parameter required to be monitored in
accordance with the requirements of Sec. 63.1283(d).
* * * * *
(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
[[Page 49597]]
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 the model of control device was tested by the
manufacturer.
(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 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 flowrate
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, repairs affected to the unit, and date the unit was
returned to service.
* * * * *
(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).
(xiii) Certification by a responsible official of truth, accuracy,
and completeness. This certification shall state that, based on
information and belief formed after reasonable inquiry, the statements
and information in the document are true, accurate, and complete.
* * * * *
(g) Electronic reporting. (1) Within 60 days after the date of
completing each performance test (defined in Sec. 63.2) as required by
this subpart you must submit the results of the performance tests
required by this subpart to EPA's WebFIRE database by using the
Compliance and Emissions Data Reporting Interface (CEDRI) that is
accessed through EPA's Central Data Exchange (CDX)(www.epa.gov/cdx).
Performance test data must be submitted in the file format generated
through use of EPA's Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/index.html). Only data collected using test
methods on the ERT Web site are subject to this requirement for
submitting reports electronically to WebFIRE. Owners or operators who
claim that some of the information being submitted for performance
tests is confidential business information (CBI) must submit a complete
ERT file including information claimed to be CBI on a compact disk or
other commonly used electronic storage media (including, but not
limited to, flash drives) to EPA. The electronic media must be clearly
marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention:
WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703.
The same ERT file with the CBI omitted must be submitted to EPA via CDX
as described earlier in this paragraph. At the discretion of the
delegated authority, you must also submit these reports, including the
confidential business information, to the delegated authority in the
format specified by the delegated authority.
(2) All reports required by this subpart not subject to the
requirements in paragraph (g)(1) of this section must be sent to the
Administrator at the appropriate address listed in Sec. 63.13. The
Administrator or the delegated authority may request a report in any
form suitable for the specific case (e.g., by commonly used electronic
media such as Excel spreadsheet, on CD or hard copy). The Administrator
retains the right to require submittal of reports subject to paragraph
(g)(1) of this section in paper format.
0
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.
* * * * *
0
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 49598]]
Table 2 to Subpart HHH of Part 63--Applicability of 40 CFR Part 63
General Provisions to Subpart HHH
------------------------------------------------------------------------
General provisions Applicable to
reference 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 Yes. ....................
(a)(8).
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).......... 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)........... Yes.................
Sec. 63.4(a)(2)........... Yes.................
Sec. 63.4(a)(3)........... No.................. Section reserved.
Sec. 63.4(a)(4)........... No.................. Section reserved.
Sec. 63.4(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)........... 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)........... 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) 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)........... 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. ....................
[[Page 49599]]
Sec. 63.6(h)(1)........... No. ....................
Sec. 63.6(h)(2)........... Yes. ....................
Sec. 63.6(h)(3)........... No.................. Section reserved.
Sec. 63.6(h)(4) through Yes. ....................
(h)(9).
Sec. 63.6(i)(1) through Yes. ....................
(i)(14).
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(a)(4)........... 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. ....................
Sec. 63.8(c)(1)(i)........ No.
Sec. 63.8(c)(1)(ii)....... Yes.
Sec. 63.8(c)(1)(iii)...... No. ....................
Sec. 63.8(c)(2)........... Yes. ....................
Sec. 63.8(c)(3)........... Yes. ....................
Sec. 63.8(c)(4)........... No. ....................
Sec. 63.8(c)(5) through Yes. ....................
(c)(8).
Sec. 63.8(d)(1)........... Yes. ....................
Sec. 63.8(d)(2)........... 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 Yes. ....................
(f)(5).
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)........... 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).............. Yes. ....................
Sec. 63.9(g).............. Yes. ....................
Sec. 63.9(h)(1) through Yes. ....................
(h)(3).
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. ....................
[[Page 49600]]
Sec. 63.10(b)(2)(i)....... No. ....................
Sec. 63.10(b)(2)(ii)...... No.................. See Sec.
63.1284(f) for
recordkeeping of
(1) occurrence and
duration and (2)
actions taken
during malfunction.
Sec. 63.10(b)(2)(iii)..... Yes. ....................
Sec. 63.10(b)(2)(iv) No. ....................
through (b)(2)(v).
Sec. 63.10(b)(2)(vi) Yes. ....................
through (b)(2)(xiv).
Sec. 63.10(b)(3).......... No. ....................
Sec. 63.10(c)(1).......... Yes. ....................
Sec. 63.10(c)(2) through No.................. Sections reserved.
(c)(4).
Sec. 63.10(c)(5) through Yes. ....................
(c)(8).
Sec. 63.10(c)(9).......... No.................. Section reserved.
Sec. 63.10(c)(10) through No.................. See Sec.
(c)(11). 63.1284(f) for
recordkeeping of
malfunctions.
Sec. 63.10(c)(12) through Yes. ....................
(c)(14).
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.................. Section reserved.
Sec. 63.10(e)(3)(i)(D).... Yes. ....................
Sec. 63.10(e)(3)(ii) Yes. ....................
through (e)(3)(viii).
Sec. 63.10(f)............. Yes. ....................
Sec. 63.11(a) through (e). Yes. ....................
Sec. 63.12(a) through (c). Yes. ....................
Sec. 63.13(a) through (c). Yes. ....................
Sec. 63.14(a) through (q). Yes. ....................
Sec. 63.15(a) and (b)..... Yes. ....................
------------------------------------------------------------------------
[FR Doc. 2012-16806 Filed 8-15-12; 8:45 am]
BILLING CODE 6560-50-P