[Federal Register Volume 79, Number 108 (Thursday, June 5, 2014)]
[Proposed Rules]
[Pages 32502-32521]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2014-12951]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 49
[EPA-HQ-OAR-2011-0151; FRL-9910-71-OAR]
RIN 2060-AS27
Managing Emissions From Oil and Natural Gas Production in Indian
Country
AGENCY: Environmental Protection Agency (EPA).
ACTION: Advance notice of proposed rulemaking.
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SUMMARY: The purpose of this Advance Notice of Proposed Rulemaking
(ANPR) is to solicit broad feedback on the most effective and efficient
means of implementing the Environmental Protection Agency's (EPA)
Indian Country Minor New Source Review program for sources in the oil
and natural gas production segment of the oil and natural gas sector.
In particular, this ANPR discusses potential new source permitting
approaches to address emissions from proposed new and modified oil and
natural gas production activities. One approach is a general permit,
which could serve as a streamlined permitting approach for addressing
emissions from new and modified minor sources and minor modifications
at major sources under the Indian Country Minor NSR rule. Another
approach is a Federal Implementation Plan, which could address
emissions from new and modified minor sources and minor modifications
at major sources. Other possible approaches include a permit by rule,
which is another streamlined permitting approach. The EPA is requesting
comments on all available new source permitting approaches and will
take this feedback into consideration in developing a notice of
proposed rulemaking for this sector under the Indian Country Minor NSR
program.
In addition, while the focus of this ANPR is on permitting
approaches for proposed new oil and natural gas production activities,
the EPA believes that managing emissions from existing oil and natural
gas sources in Indian country would result in greater consistency with
surrounding state requirements. Addressing existing sources may be
particularly important given the significant activity associated with
the sector in Indian country and the resultant need to protect public
health, balanced with tribes' inherent sovereignty and interest in
promoting economic development. If the EPA decides to address existing
oil and natural gas production sources, then we will be interested in
considering comments regarding whether a FIP should be the mechanism
used to establish permitting requirements for new and existing sources,
especially in areas where surrounding states regulate existing sources.
DATES: Comments must be received on or before July 21, 2014.
ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2011-0151, by one of the following methods:
www.regulations.gov: Follow the on-line instructions for
submitting comments.
Email: [email protected]. Include Docket ID No. EPA-
HQ-OAR-2011-0151 in the subject line of the message.
Fax: (202) 566-9744, attention Docket ID No. EPA-HQ-OAR-2011-0151.
Mail: Attention Docket ID No. EPA-HQ-OAR-2011-0151, EPA, Mailcode:
6102T, 1200 Pennsylvania Ave. NW., Washington, DC 20460. Please include
a total of two copies.
Hand Delivery: The EPA Docket Center, Public Reading Room, EPA
West, Room 3334, 1301 Constitution Ave. NW., Washington, DC 20460,
Attention Docket ID No. EPA-HQ-OAR-2011-0151. Such deliveries are only
accepted during the Docket's normal hours of operation, and special
arrangements should be made for deliveries of boxed information.
Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2011-0151. The EPA's policy is that all comments received will be
included in the public docket without change and may be made available
online at www.regulations.gov, including any personal information
provided, unless the comment includes information claimed to be
Confidential Business Information (CBI) or other information whose
disclosure is restricted by statute. Do not submit information that you
consider to be CBI or otherwise protected through www.regulations.gov
or email. The www.regulations.gov Web site is an ``anonymous access''
system, which means the EPA will not know your identity or contact
information unless you provide it in the body of your comment. If you
send an email comment directly to the EPA without going through
www.regulations.gov, your email address will be automatically captured
and included as part of the comment that is placed in the public docket
and made available on the internet. If you submit an electronic
comment, the EPA recommends that you include your name and other
contact information in the body of your comment and with any disk or
CD-ROM you submit. If the EPA cannot read your comment due to technical
difficulties and cannot contact you for clarification, the EPA may not
be able to consider your comment. Electronic files should avoid the use
of special characters, any form of encryption, and be free of any
defects or viruses. For additional instructions on submitting comments,
go to Section I.C of the SUPPLEMENTARY INFORMATION section of this
document.
Docket: The EPA has established a docket for this action under
Docket ID Number EPA-HQ-OAR-2011-0151. All documents in the docket are
listed in the www.regulations.gov index. Although listed in the index,
some information is not publicly available,
[[Page 32503]]
e.g., CBI or other information whose disclosure is restricted by
statute. Certain other material, such as copyrighted material, will be
publicly available only in hard copy. Publicly available docket
materials are available either electronically in www.regulations.gov or
under Docket ID Number EPA-HQ-OAR-2011-0151, EPA/DC, EPA West, Room
3334, 1301 Constitution Ave. NW., Washington, DC. The Public Reading
Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday,
excluding legal holidays. The telephone number for the Public Reading
Room is (202) 566-1744, and the telephone number for the Air Docket is
(202) 564-1742.
FOR FURTHER INFORMATION CONTACT: Christopher Stoneman, Outreach and
Information Division, Office of Air Quality Planning and Standards,
(C304-01), Environmental Protection Agency, Research Triangle Park,
North Carolina, 27711, telephone number (919) 541-0823, facsimile
number (919) 541-0072, email address: [email protected].
SUPPLEMENTARY INFORMATION: Throughout this document, ``reviewing
authority,'' ``we,'' ``us'' and ``our'' refer to the EPA.
I. General Information
A. Does this action apply to me?
Entities potentially affected by this proposed action include
owners and operators of facilities located or planning to locate in
Indian country as defined in 18 U.S.C. 1151 and as provided in the
Indian Country Minor NSR rule if the facilities are from oil and
natural gas source categories such as the following:
Table 1--Example Oil and Natural Gas Production Source Categories
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North American Industry
Industry category Classification System
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Crude Petroleum and Natural Gas (SIC 1311) 211111--Crude Petroleum and
Natural Gas Extraction
Natural Gas Liquids (SIC 1321)............ 211112--Natural Gas Liquid
Extraction
Drilling Oil and Gas Wells (SIC 1381)..... 213111--Drilling Oil and Gas
Wells
Oil and Gas Field Services (SIC 1389)..... 213112--Support Activities
for Oil and Gas Operations
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This list is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be potentially affected
by this action. If you have any questions regarding the applicability
of this action to a particular entity, contact the person listed in the
preceding section.
B. What should I consider as I prepare my comments to the EPA?
1. Submitting CBI
Do not submit CBI information to the EPA through
www.regulations.gov or email. Clearly mark the part or all of the
information that you claim to be CBI. For CBI information in a disk or
CD-ROM that you mail to the EPA, mark the outside of the disk or CD-ROM
as CBI and then identify electronically within the disk or
CD[n x dash]ROM the specific information that is claimed as
CBI. In addition to one complete version of the comment that includes
information claimed as CBI, a copy of the comment that does not contain
the information claimed as CBI must be submitted for inclusion in the
public docket. Information so marked will not be disclosed except in
accordance with procedures set forth in 40 Code of Federal Regulations
(CFR) Part 2.
Send or deliver information identified as CBI only to the following
address: Roberto Morales, OAQPS Document Control Officer (C404-02),
Office of Air Quality Planning and Standards, EPA, Research Triangle
Park, North Carolina 27711, Attention Docket ID No. EPA-HQ-OAR-2011-
0151.
2. Tips for preparing comments
When submitting comments, remember to:
Identify the action by docket number and other identifying
information (subject heading, Federal Register date and page number).
Follow directions--The agency may ask you to respond to
specific questions or organize comments by referencing a CFR part or
section number.
Explain why you agree or disagree, suggest alternatives,
and substitute language for your requested changes.
Describe any assumptions and provide any technical
information and/or data that you used.
If you estimate potential costs or burdens, explain how
you arrived at your estimate in sufficient detail to allow for it to be
reproduced.
Provide specific examples to illustrate your concerns and
suggest alternatives.
Explain your views as clearly as possible, avoiding the
use of profanity or personal threats.
Make sure to submit your comments by the comment period
deadline identified.
C. Where can I get a copy of this document and other related
information?
In addition to being available in the docket, an electronic copy of
this ANPR will also be available on the World Wide Web. Following
signature by the EPA Administrator, a copy of this notice will be
posted in the regulations and standards section of our NSR home page
located at http://www.epa.gov/nsr and on the tribal NSR page at http://www.epa.gov/air/tribal/tribalnsr.html.
II. Purpose of This Advance Notice of Proposed Rulemaking
The primary purpose of this ANPR is to solicit broad feedback on
the most effective and efficient means of implementing the EPA's Indian
Country Minor NSR program for proposed new and modified sources in the
oil and natural gas production segment of the oil and natural gas
sector in Indian country. The ANPR seeks input on approaches that may
be used to manage emissions from oil and natural gas production in
Indian country and solicits comment on a variety of issues, including:
(1) Whether the approach should address emissions from new and modified
units only or (as discussed below) existing source emissions as well;
(2) the advantages and disadvantages of available approaches to manage
emissions impacts from the oil and natural gas sector in Indian
country; (3) the activities and pollutants that warrant regulation; (4)
the coordination of compliance between any approach selected and the
Indian Country Minor NSR program; and (5) appropriate emission control
requirements. We are considering the following new source permitting
approaches for managing oil and natural gas emissions from proposed new
and modified sources in Indian country: (1) A CAA minor NSR general
permit; (2) a FIP; and (3) other available approaches such as a permit
by rule. The EPA seeks feedback on all aspects of available approaches
and will take the comments into consideration in developing a notice of
proposed rulemaking for this sector under the Indian country Minor NSR
program.
In July 2011, the EPA finalized a rule that includes, among other
things, a minor NSR permitting program that applies in Indian country
and, beginning on September 2, 2014,\1\ that requires new minor
sources, and minor and major sources that undertake a minor
modification to obtain a pre-construction permit. We call this
[[Page 32504]]
regulation the ``Federal Minor New Source Review Program in Indian
Country.'' 76 FR 38748, July 1, 2011. We call a permit issued under
this program a minor NSR permit. Minor NSR permits address emissions
from new and modified units at permitted sources.
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\1\ EPA has proposed to extend this deadline with respect to
true minor sources in the oil and natural gas sector. 79 FR 2546,
Jan. 14, 2014.
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In an effort to streamline minor source permitting under this
program, the EPA plans to issue general permits for new true minor
sources for certain source categories. A general permit is a type of
permit that contains standardized requirements that can apply to one or
more sources in a given source category. One of the categories for
which the EPA is considering issuing a general permit is the oil and
natural gas production segment of the oil and natural gas sector.
Specifically, the oil and natural gas production segment includes
natural gas production that occurs prior to the natural gas entering
natural gas processing plants or prior to the natural gas entering the
transmission and storage segment when there is no natural gas
processing plant, and crude oil production operations that generally
occur prior to the oil entering crude oil storage and transmission
terminals where the oil is loaded for transport to refineries. The EPA
believes that the creation and issuance of a general permit may be
appropriate because it simplifies the permit issuance process for minor
sources so that reviewing authorities and others (interested public,
regulated source) can ensure environmental protection without expending
resources unnecessarily by developing numerous site specific permits
that include substantially similar permit requirements. The general
permit approach was proposed recently for a number of source categories
as part of the Indian Country Minor NSR program. 79 FR 2546, Jan. 14,
2014.
While we believe that a general permit is a possible streamlining
mechanism for issuing permits to new and modified oil and natural gas
production facilities, we are also exploring the possibility of
alternate mechanisms to regulate emissions from this segment. One
approach is a FIP, which could be used to establish regulatory
requirements for emissions from new and modified minor sources and
minor modifications at major sources within the oil and natural gas
production segment. This ANPR is the first instance in which the EPA is
raising the possibility of promulgating a FIP to implement its minor
NSR program with respect to oil and natural gas production activities
in Indian country. A FIP was promulgated in 2013 for oil and natural
gas sources located in the Fort Berthold Indian Reservation (located in
North Dakota, within the Williston Basin), and the approach has largely
been viewed as successful in that instance. One difference between a
FIP and a general permit is that a FIP would not require the submission
of applications by sources and the review and approval of these
applications by a reviewing authority prior to construction. Instead,
the requirements would directly apply to sources subject to the
regulation. A FIP could obviate the need for new or modified individual
minor sources to obtain permits because the FIP could directly
establish regulatory requirements like those established under a permit
(or general permit) for those sources and would be federally
enforceable.
Other new source permitting approaches may be available as well,
including the possibility of a permit by rule approach for true minor
oil and natural gas sources. The permit by rule approach would address
emissions from new and modified units at the permitted source. A permit
by rule is a standard set of requirements that can apply to multiple
sources with similar emissions and other characteristics. It is very
similar to a general permit. Unlike a general permit, however, permit
by rule requirements are promulgated using a rulemaking process (i.e.,
the requirements are included in the Code of Federal Regulations),
rather than establishing the requirements through a general permit
document that undergoes notice and comment (i.e., the requirements are
included in the general permit document). The permit by rule mechanism
is simpler than a site-specific permit or a general permit because it
further reduces the time permitting authorities must devote to
reviewing permit applications and issuing permits for source categories
or emissions generating activities that pose a lower environmental
concern. Site-specific permit applications and permit applications
under a general permit must be reviewed and approved by a reviewing
authority prior to construction or modification. Under a permit by
rule, a reviewing authority would receive notification from an
individual source that it meets all eligibility criteria for coverage
by the permit, but would not need to approve the source's notice prior
to the source beginning to construct or modify. This approach
simplifies the permitting process but would not allow the public the
opportunity (as would be available under a site-specific or a general
permit) to object, except by judicial challenge, to a particular source
receiving coverage under the permit by rule. Further discussion of the
proposed permit by rule approach is available in the recent action
entitled ``General Permits and Permits by Rule for the Federal Minor
New Source Review Program in Indian Country,'' 79 FR 2546 at 2566-67,
Jan. 14, 2014.
While the focus of this ANPR is on permitting approaches for new
oil and natural gas sources, the EPA believes that managing emissions
from existing oil and natural gas sources also may be important given
the significant activity associated with the sector in Indian country
and the resultant need to protect public health and the environment,
balanced with tribes' inherent sovereignty and interest in promoting
economic development. Although NSR general permits and permits by rule
are not approaches that can be used to address existing sources, a FIP
could extend to existing sources; this is a key distinction between
general permits and permits by rule versus a FIP. Addressing existing
sources through a FIP could be especially useful in areas for which
surrounding state requirements apply to existing oil and natural gas
sources located on lands that are within a state's jurisdiction.
Concerns related to the air quality impacts from existing oil and
natural gas sources in Indian country are discussed further in Section
IV. of this notice. Given these concerns, the EPA is requesting
comments on whether a FIP, if that is determined to be an appropriate
approach for new source permitting for oil and natural gas sources,
should also be used to establish requirements for existing oil and
natural gas sources. A FIP would effectively function as a permit by
rule, however unlike the permit by rule and general permit approaches
which are limited to addressing new and modified sources in the NSR
context, a FIP could also address existing sources.
Although the Indian Country Minor NSR rule does not include
greenhouse gases, actions taken to reduce volatile organic compound
(VOC) emissions--whether through a general permit, a FIP, or other
approaches--also likely will reduce methane as a co-benefit. Methane,
the primary constituent of natural gas, is a potent greenhouse gas--
more than 20 times as potent as carbon dioxide when emitted directly to
the atmosphere. In 2012, 28 percent of methane emissions nationwide
were attributed to sources in the oil and natural gas sector. On March
28, 2014, the Obama Administration released a key element called for in
the President's Climate Action Plan: A Strategy to Reduce Methane
Emissions. The
[[Page 32505]]
strategy summarizes the sources of methane emissions, commits to new
steps to cut emissions of this potent greenhouse gas, and outlines the
Administration's efforts to improve the measurement of these emissions.
The strategy builds on progress to date and takes steps to further cut
methane emissions from several sectors, including the oil and natural
gas sector.
III. Background on the Oil and Natural Gas Sector
A. What is the oil and natural gas sector?
The oil and natural gas sector includes operations involved in the
extraction and production of oil and natural gas, as well as the
processing, transmission and distribution of natural gas. Specifically
for oil, the sector includes all operations from the well to the point
of custody transfer at a petroleum refinery. For natural gas, the
sector includes all operations from the well to the final end user. The
oil and natural gas sector can generally be separated into four
segments: (1) Oil and natural gas production; (2) natural gas
processing; (3) natural gas transmission and storage; and (4) natural
gas distribution. Each of these segments is briefly discussed below.
This ANPR is focused on the first segment (oil and natural gas
production), because this is the segment we believe would constitute
the majority of the minor sources that would need a minor source permit
in Indian Country. If, following the review of comments received via
this ANPR, we decide that the general permit approach is preferable to
a FIP, then we anticipate that the bulk of the oil and natural gas
sources that we would permit would be from the production segment
(generally, sources in other segments tend to be larger, potentially
major sources such as gas processing plants). Because the FIP would be
intended to replace the minor source program for oil and natural gas
sources, we believe that it makes the most sense to focus on the
production segment for both the general permit approach and the FIP
approach. We welcome comment on this rationale.
The oil and natural gas production segment includes the wells and
all related processes used in the extraction, production, recovery,
lifting, stabilization, and separation or treatment of oil and/or
natural gas (including condensate). Production components may include,
but are not limited to, wells and related casing head, tubing head and
``Christmas tree'' piping, as well as pumps, compressors, heater
treaters, separators, storage vessels, pneumatic devices and
dehydrators. Production operations also include the well drilling,
completion and workover processes and include all the portable non-
self-propelled apparatus associated with those operations. Production
sites include not only the sites where the wells themselves are
located, but also include stand-alone ``pads'' where oil, condensate,
produced water, and natural gas from several wells may be separated,
stored, and treated. The production segment also includes the low to
medium pressure, smaller diameter, gathering pipelines and related
components that collect and transport the oil, natural gas and other
materials and wastes from the wells or well pads.
The natural gas production segment ends where the natural gas
enters a processing plant. In situations where there is no processing
plant, the natural gas production segment ends at the point where the
natural gas enters the transmission segment for long-line transport.
The crude oil production segment ends at the storage and load-out
terminal which is used for transport of the crude oil to a petroleum
refinery via trucks or railcars. The petroleum refinery is not
considered a part of the oil and natural gas sector. Thus, with respect
to crude oil, the oil and natural gas sector ends where crude oil
enters the petroleum refinery.
The second segment, natural gas processing, consists of separating
certain hydrocarbons and fluids from the natural gas to produce
``pipeline quality'' dry natural gas. While some of the processing can
be accomplished in the production segment, the complete processing of
natural gas takes place in the natural gas processing segment. Natural
gas processing operations separate and recover natural gas liquids
(NGL) or other non-methane gases and liquids from a stream of produced
natural gas through components performing one or more of the following
processes: Oil and condensate separation, water removal, separation of
NGL, sulfur and carbon dioxide removal, fractionation of natural gas
liquid and other processes, such as the capture of carbon dioxide
separated from natural gas streams for delivery outside the facility.
The pipeline quality natural gas leaves the natural gas processing
segment and enters the third segment, natural gas transmission and
storage. Pipelines in the natural gas transmission and storage segment
can be interstate pipelines that carry natural gas across state
boundaries or intrastate pipelines, which transport the natural gas
within a single state. While interstate pipelines may be of a larger
diameter and operated at a higher pressure, the basic components are
the same. To ensure that the natural gas flowing through any pipeline
remains pressurized, compression of the natural gas is required
periodically along the pipeline. This is accomplished by compressor
stations usually placed at between 40- and 100-mile intervals along the
pipeline. At a compressor station, the natural gas enters the station,
where it is compressed by reciprocating or centrifugal compressors. In
addition to the pipelines and compressor stations, the natural gas
transmission and storage segment includes underground storage
facilities.
The fourth segment, natural gas distribution, is the final step in
delivering natural gas to customers. The natural gas enters the
distribution segment from delivery points located on interstate and
intrastate transmission pipelines to business and household customers.
The delivery point where the natural gas leaves the transmission and
storage segment and enters the distribution segment is often called the
``city gate.'' Typically, natural gas supply companies take ownership
of the natural gas at the city gate.
Natural gas distribution systems consist of thousands of miles of
piping, including mains and service pipelines to the customers.
Distribution systems sometimes include compressor stations, although
they are considerably smaller than transmission compressor stations.
Distribution systems include metering stations, which allow
distribution companies to monitor the natural gas in the system.
Essentially, these metering stations measure flow rates and allow
distribution companies to track natural gas as it flows through the
system.
Emissions can occur from a variety of processes and points
throughout the oil and natural gas production segment. In Section
III.B., we explain these processes and pollutant emissions points in
more detail. In sum, emission sources include, but are not necessarily
limited to, drilling and completion with the associated flowback
activities; extraction operations; and road, pipeline and well pad
construction. Also, significant emissions can be released from the
operation of reciprocating internal combustion engines and combustion
turbines that power compressors or provide electricity throughout the
oil and natural gas production segment. Pollutants emitted from these
activities that we regulate through the Indian Country Minor NSR
permitting program
[[Page 32506]]
(regulated NSR pollutants) include VOC, NOX, sulfur dioxide
(SO2), particulate matter (PM, PM10,
PM2.5), hydrogen sulfide, carbon monoxide (CO) and various
sulfur compounds. Hydrogen sulfide and SO2 are emitted from
production and processing operations that handle and treat sour gas.\2\
In Section VII. we request comment on the pollutant-emitting activities
and the pollutants that might warrant regulation through a general
permit, FIP, or other approach.
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\2\ Sour gas is natural gas with more than 5.7 milligrams of
hydrogen sulfide per normal cubic meters (0.25 grains/100 standard
cubic feet), see AP-42 Compilation of Air Pollutant Emission
Factors, Chapter 5.0 Introduction to Petroleum Industry, Section 5.3
Natural Gas Processing, available at http://www.epa.gov/ttnchie1/ap42/ch05/final/c05s03.pdf.
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B. What equipment is used for exploration and production and what
emissions are associated with the use of this equipment?
1. Drill Rig Emissions
Air pollution from oil and natural gas drilling rigs originates
from the combustion of diesel fuel in diesel engines used to drive
electrical generators that power the drilling equipment. Diesel engines
emit NOX, SO2, CO, and PM. The amount of
emissions generated from an engine can vary greatly depending on
factors such as the age of the engine, the drilling cycle, and the
amount of energy required to penetrate a rock formation while drilling.
The engine may be run through different activity modes including
standby, drilling, tripping, back reaming, casing running, and
cementing. The drilling and back reaming modes are the most power
intensive operational modes.\3\
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\3\ E. Quinlan, R. van Kuilenberg, T. Williams, and G.
Thonhauser, ``The Impact of Rig Design and Drilling Methods on the
Environmental Impact of Drilling Operations,'' Conference of
American Assn. of Drilling Engineers, April 12-14, 2011, available
at www.aade.org/app/download/6858447204/AADE-11-NTCE-61.pdf.
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2. Natural gas Wellhead and Field Gathering Compressor Engines
In production operations, compressors assist in increasing the
pressure and moving the natural gas from the well site downstream to a
gathering facility and beyond for further processing. Two types of
compressor designs are commonly used: Reciprocating and centrifugal.
In a reciprocating compressor, natural gas enters a suction
manifold, and then flows into a compression cylinder. The natural gas
is compressed in the cylinder by a crankshaft that runs a reciprocal
motion piston and is powered by an internal combustion engine.
Reciprocating compressors are designed with a rod packing seal system.
The compressor rod packing system consists of a series of flexible
rings that create a seal around the piston rod to prevent natural gas
from escaping between the rod and the inboard cylinder head. All such
packing systems vent natural gas under normal conditions, but the
leakage rate will increase over time as the rings become worn. When
this occurs, the packing system will need to be replaced to prevent
excessive leaking from the compression cylinder.
Centrifugal compressors use a rotating disk or impeller to increase
the velocity of the natural gas which is directed to a divergent duct
section that converts the velocity energy to pressure energy.
Centrifugal compressors require seals around the rotating shaft to
prevent gases from escaping where the shaft exits the compressor
casing. Although dry seals are used in most new centrifugal
compressors, some compressors use high-pressure wet seals (comprised of
oil) as a barrier against escaping natural gas. The circulated oil
entrains and absorbs some compressed natural gas. VOC emissions occur
when the oil is stripped of natural gas that it absorbed at the high-
pressure seal face. This process is known as degassing and is a normal
function of the seal oil recirculation process.
3. Liquids Unloading
As a well ages, the reservoir's pressure declines and the velocity
of fluid through the tubing that conveys the natural gas to the surface
also decreases. As velocity decreases, liquids can accumulate on the
walls of the tubing. Eventually, the natural gas velocity in the tubing
may not be sufficient to lift liquids to the surface. When liquids
accumulate in the bottom of the well tube, natural gas flow is
restricted or stops.
A common approach operators use to restore the flow of the well is
to perform a ``blowdown.'' To perform a blowdown, the operator shuts in
the well temporarily to allow the bottom hole pressure to increase as
natural gas migrates from the formation to the well. When the pressure
has increased sufficiently, the operator releases the pressure in the
well rapidly by venting it to the atmosphere until it reaches
atmospheric pressure. The pressure drop blows the liquid out of the
well. Releases of VOC occur as the well is vented to the atmosphere.
This process does not provide a permanent solution, and operators will
likely need to repeat the process over various intervals of time as
fluids re-accumulate in the well tubing. These intervals vary from well
to well and generally decrease as the well continues to age and
requires more frequent unloading. Each time, the process releases
additional VOC to the air.
4. Glycol Dehydration
Natural gas is often produced with a mixture of water and other
hydrocarbons. A glycol dehydrator is used to remove the water vapor
from the natural gas stream. In the first stage, the natural gas
mixture is passed through an absorber where water vapor is absorbed.
Most dehydration units use triethylene glycol as the absorbent.
Following the preliminary dehydration stage, the glycol mixture either
first moves to a flash tank where some gases are removed by reducing
the pressure, or moves directly to a regenerator, where the triethylene
glycol is heated to remove absorbed water from the glycol fluid. During
this process, VOC, carbon dioxide, nitrogen, and hydrogen sulfide are
boiled off and vented to the atmosphere along with the water vapor
being removed.\4\
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\4\ See, e.g., Anadarko Petroleum Corp. and the Domestic
Petroleum Council, ``Natural Gas Dehydration: Lessons Learned from
the Natural Gas STAR Program,'' Producers Technology Transfer
Workshop, College Station, TX, May 17, 2007, available at http://epa.gov/gasstar/documents/workshops/college-station-2007/8-dehydrations.pdf.
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5. Oil, Condensate, and Produced Water Storage Tanks
Storage tanks or vessels are used at well production sites to store
crude oil, produced water, and condensate (hydrocarbon liquids)
extracted from the well. Storage tanks are typically installed as a
group of similar or identical vessels known as a tank battery.
VOC emissions are released from a storage tank due to flashing
losses, working losses, or breathing losses. Flashing losses occur when
liquids from a higher pressure wellhead or separator are introduced
into a lower pressure storage tank, usually operating at atmospheric
pressure. In this situation, the pressure of the liquid drops, causing
the entrained gas or some of the liquid to vaporize (flash). If the gas
is not captured, it is released to the air. Typically, the larger the
pressure drop (i.e. the higher the separator pressure compared to the
storage tank pressure), the more flash emissions will occur in the
storage tank. The temperature of the liquid may also influence the
amount of flash emissions. Working losses occur when vapors in the
headspace of a fixed roof tank are displaced to the air when the
operator fills or empties the tank.
[[Page 32507]]
Breathing losses occur due to normal evaporation of liquid in the tank
in response to temperature changes or other equilibrium effects. In the
oil and natural gas production sector, flash emissions are much greater
than the working and breathing losses.
The volume of emissions from a storage tank depends on many
factors. Lighter crude oils flash more hydrocarbons than heavier crude
oils. In storage tanks where the oil is frequently cycled and the
overall throughput is high, working losses are higher. Additionally,
the operating temperature and pressure of oil as it moves from a
separator to a storage tank affects the volume of flashed gases coming
out of the oil. VOCs are the predominant emissions from storage tanks.
6. Truck Loadout
Oil and natural gas condensate are transported from production
operations to natural gas processing plants and/or crude oil transport
terminals. VOC emissions from the storage tanks occur during the load
out (withdrawal) process. Loading losses occur as hydrocarbon vapors in
``empty'' cargo tanks are displaced to the atmosphere by the liquid
being loaded into the tanks. These vapors are a composite of (1) vapors
formed in the empty tank by evaporation of residual product from
previous loads, (2) vapors transferred to the tank in vapor balance
systems as product is being unloaded, and (3) vapors generated in the
tank as the new product is being loaded.
7. Pneumatic Devices
The oil and natural gas production segment uses a variety of
process control devices to moderate temperature, pressure, flow rate,
and fluid volume. These devices operate pneumatically, electrically, or
mechanically. Electrical and mechanical devices do not generate
emissions. Most devices in the industry are pneumatic controllers.
Pneumatic controllers are automated instruments that use
differences in the pneumatic pressure of a gas to transmit a process
signal or adjust position. In the vast majority of applications, the
oil and natural gas production segment uses pneumatic controllers that
make use of readily available high-pressure natural gas to provide the
required energy and control signals.
Pneumatic devices can release a significant amount of VOC emissions
during normal operations. In these ``gas-driven'' pneumatic
controllers, natural gas may be released with every valve movement,
and/or continuously from the valve control pilot. The rate at which the
continuous release occurs is referred to as the bleed rate. Bleed rates
are dependent on the design and operating characteristics of the
device. Similar designs will have similar steady-state rates when
operated under similar conditions. There are three basic designs with
emissions varying from each: (1) Continuous bleed devices are used to
modulate flow, liquid level, or pressure, and gas is vented
continuously at a rate that may vary over time; (2) snap-acting devices
release gas only when they open or close a valve or as they throttle
the gas flow; and (3) self-contained devices release gas to a
downstream pipeline instead of to the atmosphere.\5\
---------------------------------------------------------------------------
\5\ EC/R, Inc., prepared for U.S. EPA, Office of Air Quality
Planning and Standards, Sector Policies and Programs Division,
``Background Technical Support Document for Proposed Standards--Oil
and Natural Gas Sector: Standards of Performance for Crude Oil and
Natural Gas Production, Transmission and Distribution,'' July 2011,
EPA-453/R-11-002 at 5-2, available at http://www.epa.gov/airquality/oilandgas/pdfs/20110728tsd.pdf.
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Continuous bleed pneumatic controllers can be classified into two
types based on their emissions rates: (1) High-bleed controllers; and
(2) low-bleed controllers. A high-bleed controller has a bleed rate in
excess of 6 standard cubic feet per hour (scfh), while low-bleed
devices bleed at a rate less than or equal to 6 scfh.\6\
---------------------------------------------------------------------------
\6\ Id.
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8. Phase Separation
Underground crude oil and natural gas can contain many lighter
hydrocarbons in solution. When the hydrocarbon product is brought to
the surface and processed, many of the dissolved lighter hydrocarbons
(as well as water) are removed through a series of high-pressure and
low-pressure separators. Crude oil and natural gas under high pressure
conditions are passed through either a two phase separator (where the
associated gas is removed and any oil and water remain together) or a
three phase separator (where the associated gas is removed and the oil
and water are also separated). At the separator, low pressure gas is
physically separated from the high pressure oil. The remaining low
pressure oil is then injected into a gathering pipeline or directed to
a storage vessel where it is stored for a period of time before being
shipped off-site. The remaining hydrocarbons in the oil may be released
from the oil as vapors in the storage vessels.
A heater-treater is a device used to break up emulsions and
facilitate removal of unwanted hydrocarbons, contaminants and water
from the well stream before oil and natural gas are sent to the
gathering pipeline or tank battery. A heater-treater warms the well
stream and prevents the formation of ice and natural gas hydrates that
may slow or stop production.
During phase separation, a blend of hydrocarbon gases, including
methane gas, may be produced as a by-product. The optimal way to manage
by-product gas is for the operator to capture the gas, process it into
a commercially sellable product, and then direct it to a pipeline where
it can be distributed for sale. When the sale of the by-product gas is
not viable, then an operator will (1) vent the gas emissions directly
to the atmosphere; (2) re-inject the gas back into the reservoir; or
(3) combust the gas to destroy it. Combustion devices predominantly
used to control VOC emissions from low pressure gas streams in oil and
natural gas production operations are ``enclosed combustors.''
``Candlestick flares'' are typically used to control higher pressure
waste gas streams.
9. Leaks
As produced natural gas moves through equipment and pipes under
elevated pressure within an oil or natural gas production facility,
leaks can occur at various locations. Fluctuations in pressure,
temperature and mechanical stresses increase the number of
opportunities for leaks from various components. Sources of fugitive
leaks include pumps, threaded and flanged connections, pressure relief
valves, open-ended lines such as vents and drains, blowdown lines, and
sampling points. Leaks can also occur due to malfunctions and pipeline
ruptures. VOC is the main criteria pollutant released during equipment
leaks.
10. Compressor Engines
Reciprocating internal combustion engines are typically used to run
reciprocating compressors, whereas combustion turbines generally power
centrifugal compressors. In some instances, an electric motor is used.
The size and horsepower of engines used at a well site vary extensively
based on the size of the field and characteristics of the natural gas.
The compressor engines typically run at full capacity for 24 hours, 7
days a week, and can emit CO, NOX, SO2, PM and
VOCs. Electric motors are not a direct source of emissions, but other
motors are.
11. External Combustion Units
External combustion units are used to generate industrial power and
produce industrial process steam and heat.
[[Page 32508]]
Examples of external combustion units in the oil and natural gas
production segment include storage tank heaters, line heaters, and
glycol reboilers. These units are typically fueled by natural gas from
the field, but they can use other gaseous and oil-based fuels, such as
propane and fuel oil 2. Primary combustion emissions are CO
and NOX, and the size and power of such units varies widely
based on the size of the field and the characteristics of the oil and/
or natural gas being produced. Electric heaters are sometimes used when
they are solar powered or when there is access to a power grid, but
they are not a direct source of emissions.
IV. Oil and Natural Gas Sector in Indian Country
A. Why are we concerned about air quality impacts from oil and natural
gas production in Indian country?
In the past few years, technological advances in oil and natural
gas extraction methods have made extraction of oil and/or natural gas
from shale, coal-bed methane and tight sandstone resources more
technologically and economically feasible than before. While
conventional oil and natural gas extraction is ongoing in some areas of
Indian country, there has been a sizeable increase in recent years in
production volume in these areas from unconventional oil and natural
gas extraction methods.\7\ Many areas of Indian country are located in
shale basins with potentially recoverable reserves including, but not
limited to, areas in North Dakota, Montana, South Dakota, Nebraska,
Kansas, Oklahoma, Texas, New York, Michigan and Wisconsin. Areas of
Indian country in western North Dakota, eastern Montana, Oklahoma and
Texas lie within tight sandstone basins with recoverable resources, and
coal bed methane reserves may exist under Indian country located in the
Northeastern and Southwestern United States.
---------------------------------------------------------------------------
\7\ Conventional oil and natural gas resources occur in
permeable sandstone and carbonate deposits, while unconventional
resources exist in shale and sedimentary rock formations.
Unconventional resources are also referred to as ``tight
formations'' because their lack of permeability make them resistant
to hydrocarbon flow unless the formation is fractured. M. Ratner and
M. Tiemann, Congressional Research Service, ``An Overview of
Unconventional Oil and Natural Gas: Resources and Federal Actions,''
July 15 2013, available at http://www.fas.org/sgp/crs/misc/R43148.pdf.
---------------------------------------------------------------------------
Indian country comprises much of the Uinta and North San Juan
Basins (in Utah and the Four Corners region, respectively). According
to a Western Regional Air Partnership (WRAP) emissions inventory report
focusing on a region spanning New Mexico, Colorado, Utah, Wyoming,
Montana, and North Dakota, oil and natural gas production sources
contribute the majority of the emissions of NOX and a large
portion of the VOC emissions in both the Uinta Basin and Northern San
Juan Basin.8 9 A significant number of oil and natural gas
production sources also exist in the South San Juan, Wind River, and
Williston Basins, all of which encompass areas of Indian country.
Although the WRAP report included limited areas of Indian country
within the United States, we believe that the level of activity in
these areas could represent the kind of emissions we can expect in
Indian country in other areas across the United States. Furthermore, as
discussed in Section IV.B, Indian country lands that contain
commercially viable oil and natural gas reserves are currently
experiencing widespread growth in the oil and natural gas production
segment, which could lead to increased emissions of air pollutants and
adverse air quality.
---------------------------------------------------------------------------
\8\ A. Bar-Ilan, J. Grant, R. Parikh, A. Pollack, and R. Morris,
ENVIRON International Corp., D. Henderer, Buys & Assocs., Inc., and
K. Sgamma, Western Energy Alliance, ``A Comprehensive Emissions
Inventory of Upstream Oil and Gas Activities in the Rocky Mountain
States,'' prepared for the Western Regional Air Partnership, July
2013, available at http://www.epa.gov/ttnchie1/conference/ei19/session8/barilan.pdf.
\9\ D. Helmig, C. Thompson, J. Evans, P. Boylan, J. Hueber, and
J.-H. Park, Institute of Arctic and Alpine Research (INSTAAR),
University of Colorado, Boulder, ``Highly Elevated Atmospheric
Levels of Volatile Organic Compounds in the Uintah Basin, Utah,''
Environ. Sci. Technol. (accepted for publication), March 13, 2014,
available at http://pubs.acs.org/doi/pdf/10.1021/es405046r.
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For example, during the development of the FIP for oil and natural
gas production sources located on the Fort Berthold Indian Reservation
(located in North Dakota, within the Williston Basin), the EPA
determined that hundreds of oil and natural gas production facilities
had been operating on the Reservation since 2007 and estimated that up
to an additional 2,000 wells could result from future development (see
further description of this FIP in Section V.B.).\10\ Another area of
increasing oil and natural gas development in Indian country is the
Uintah and Ouray Indian Reservation in northeast Utah, within the Uinta
Basin. According to recent National Environmental Policy Act (NEPA)
documents for oil and natural gas development in the Uinta Basin, the
Bureau of Land Management (BLM) has approved the construction of more
than 5,000 new wells, and even more projects are anticipated for future
NEPA review.\11\ This increase in development has the potential to
adversely impact air quality and will result in an increased permitting
burden for sources and reviewing authorities under the Indian Country
Minor NSR rule that is scheduled to take effect on September 2,
2014.\12\
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\10\ ``Approval and Promulgation of Federal Implementation Plan
for Oil and Natural Gas Well Production Facilities: Fort Berthold
Indian Reservation (Mandan, Hidatsa, and Arikara Nation), North
Dakota,'' 78 FR 17836, March 22, 2013. The Technical Support
Document for the Fort Berthold FIP includes a more detailed
explanation of the rule development; this document is available in
the docket for the FIP, i.e., Docket ID: EPA-R08-OAR-2012-0479, see
www.regulations.gov.
\11\ See, e.g., U.S. Dept. of the Interior, Bureau of Land
Management, ``Record of Decision for the Gasco Energy Inc. Uinta
Basin Natural Gas Development Project,'' June 18, 2012, available at
http://www.blm.gov/ut/st/en/fo/vernal/planning/nepa_.html; U.S.
Dept. of the Interior, Bureau of Land Management, ``Greater Natural
Buttes Record of Decision,'' May 8, 2012, available at http://www.blm.gov/ut/st/en/fo/vernal/planning/nepa_html.
\12\ The EPA has proposed to extend this deadline to a date
within a range between September 2, 2015 to March 2, 2016 for oil
and natural gas production sources. 79 FR 2546, Jan. 14, 2014.
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Although rapid increases in oil and natural gas production have
occurred in some areas of Indian country in recent years, uncertainties
about the extent of environmental impacts from this production in
Indian country persist despite developing policy initiatives, programs,
and industry practices to address the environmental implications of the
emissions associated with this growth. These uncertainties are due in
part to the scarcity of ambient air monitoring in some areas of Indian
country, as discussed below. Additionally, there is incomplete
emissions information for this sector in Indian country and
improvements in emissions methodologies are still evolving. See Section
IV.B. for further discussion of these issues.
At the same time, the EPA remains committed to supporting tribes'
right to self-governance and protecting their inherent sovereignty.
Uncertainties surrounding the regulation of oil and natural gas
production sources in Indian country have resulted in an ``uneven
playing field'' in some areas between Indian country and surrounding
states (i.e., sources in areas with similar air quality are not subject
to the same requirements). The EPA continues to actively reach out to
oil and natural gas organizations and other stakeholders to improve our
understanding of the potential environmental implications of oil and
natural gas production operations, and we strive to provide greater
regulatory certainty and consistency in the regulation of these
operations through enhanced data
[[Page 32509]]
collection and analysis, improved information sharing and partnerships,
and focused compliance assistance and enforcement. The EPA must address
these considerations while also meeting our trust responsibilities
regarding protection of air quality and public health in Indian
country. We believe that it is appropriate to explore measures that
reduce the administrative burden associated with regulating new minor
sources and minor modifications of existing stationary sources in a way
that: (1) Ensures the timely implementation of environmental
protections; (2) maximizes the efficient use of resources; (3)
minimizes preventable delays in economic development; and (4)
proactively mitigates potential adverse air-quality-related
environmental and public health impacts that could result from the
rapid growth in emissions from oil and natural gas production
operations.
The Indian Country Minor NSR rule allows us to manage minor source
emissions increases in Indian country and ensure that new emissions do
not cause or contribute to a National Ambient Air Quality Standard
(NAAQS) or Prevention of Significant Deterioration (PSD) increment
violation. However, industry and tribal governments have expressed
concerns that EPA Regional Office reviewing authorities may not be able
to keep pace with the volume of oil and natural gas-related permit
applications the offices may receive, and a lag in permit issuance
rates could place sources in Indian country at a competitive
disadvantage compared to similar sources located in the surrounding
state-managed lands. We are cognizant of this concern, especially in
light of the approximately 6,400 existing minor source registrations
received in the EPA Region 8 Office for facilities in the oil and
natural gas production segment.\13\
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\13\ In the Indian Country Minor NSR rule, EPA established a
registration program that required owners and operators of existing
true minor sources to file a one-time registration with the
appropriate reviewing authority by March 1, 2013. EPA's Region 8
Office has received more than 6,400 registrations from true minor
sources in the oil and natural gas sector. This far exceeded the
amount received from sources in any other category.
---------------------------------------------------------------------------
A general permit, a permit by rule (more rapid permit issuance than
a general permit), and a FIP (essentially a permit by rule, but with
the potential to additionally address existing sources) would each
allow more expeditious implementation of the minor NSR program compared
to requiring site-specific permits. Establishing requirements for
appropriate mitigation measures for a general permit or permit by rule
in areas where emissions from existing oil and natural gas production
activities are an issue could be challenging, given that these
approaches would not address existing sources.
Accordingly, today we seek comment on the appropriateness of any
available permitting or other approaches as a means for managing
emissions impacts from the growth of oil and natural gas production
emissions in Indian country through either regulation of the
construction and modification of proposed new minor sources and minor
modifications at major sources within the oil and natural gas
production segment (the permitting approach) or direct regulation of
proposed oil and natural gas sources (the FIP approach). We also seek
comment on whether and how a potential FIP should regulate emissions
from existing sources in the oil and natural gas industry to balance
economic growth with appropriate environmental protections.
B. What information do we have regarding emissions and air quality
associated with oil and natural gas production in Indian country?
Federal and state government agencies have accumulated substantial
data characterizing oil and natural gas sector activity in Indian
country. But there are still gaps in our knowledge regarding the extent
of oil and natural gas activity in Indian country and its impacts. The
EPA is making a concerted effort to improve our understanding of oil
and natural gas emissions generally, as well as improving estimates of
emissions from oil and natural gas production activity in Indian
country.
1. Federal and State Government Emissions and Other Data
According to the Office of Indian Energy and Economic Development
(IEED) at the Department of the Interior (DOI), significant oil and
natural gas production in Indian country has already occurred and there
is even greater potential for future development. As of 2012, more than
2 million acres of Indian lands accounting for about 10 percent of the
oil and natural gas production from federally regulated onshore acreage
had been leased for oil and natural gas development.\14\ The DOI
estimates that ``since 2002, annual income from energy mineral
production increased by more than 113 percent and this trend is
expected to continue for the foreseeable future.'' \15\ As of April
2014, over 6,400 minor sources in the oil and natural gas production
sector have registered with the EPA's Region 8 Office in response to
the registration requirement in the Indian Country Minor NSR rule.
---------------------------------------------------------------------------
\14\ ``Energy Development in Indian Country,'' Testimony Before
the Senate Committee on Indian Affairs, J. Gillette, Deputy Asst.
Secretary Indian Affairs, U.S. Dept. of the Interior, Feb. 16 2012,
available at http://www.doi.gov/ocl/hearings/112/IndianCountryEnergyDevelopment_021612.cfm.
\15\ Id.
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By comparing maps of Indian country in the U.S. to maps of known
conventional and unconventional oil and natural gas reserves, it is
evident that many areas of Indian country are in regions that are rich
in mineral resources. The IEED has been providing technical assistance
to various tribes to identify numerous prospects for drilling, ``by
purchasing, reprocessing and interpreting thousands of miles of 2D [two
dimensional] seismic data as well as hundreds of square miles of 3D
[three dimensional] data.'' \16\ The DOI's Indian Affairs Office
maintains an Atlas of Oil and Gas Plays on American Indian Lands as
well as information sheets on the status of oil and natural gas
reserves and drilling on a limited set of specific reservation
lands.\17\
---------------------------------------------------------------------------
\16\ Id.
\17\ For more information, see: http://www.bia.gov/WhoWeAre/AS-IA/IEED/DEMD/oilgas/index.htm.
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Growth in oil and natural gas production in Indian country is
occurring or is expected in many areas. For example, the Jicarilla
Apache Nation reports that it has almost 3,000 active and plugged oil
and natural gas wells, and 2,000 miles of natural gas-gathering
pipelines and roads, while the Ute Tribal Business Committee reports
that the Ute reservation currently has 7,000 wells, and plans to open
up an additional 150,000 acres to mineral leases.\18\ The U.S. Energy
Information Administration (EIA) reports that sales of crude oil
produced on Indian lands located primarily in North Dakota and Utah
increased 56 percent from 2003 to 2012, which is the highest recorded
level.\19\ Detailed drilling rig activity reported by EIA projects
almost a doubling of new oil production from rigs at the Bakken
formation, which underlies the Fort Berthold Indian Reservation, from
December 2012 to December 2013.\20\ The Bakken oil field covers about
200,000 square miles of the
[[Page 32510]]
subsurface of the Williston Basin that lies under parts of the States
of Montana, South Dakota, North Dakota and Montana in the United
States, and the provinces of Manitoba and Saskatchewan in Canada.
---------------------------------------------------------------------------
\18\ J. Kemp, Reuters Daily Online Publications, ``Tribes call
for faster drilling on Indian lands,'' Feb. 5, 2013, available at
http://www.reuters.com/article/2013/02/05/column-kemp-oilgas-indian-lands-idUSL5N0B5A9W20130205.
\19\ U.S. EIA, ``Sales of Fossil Fuels Produced from Federal and
Indian Lands, FY 2003 through FY 2012,'' May 30, 2013, available at
http://www.eia.gov/analysis/requests/federallands/.
\20\ U.S. EIA, ``Drilling Productivity Report for Key Tight Oil
and Shale Gas Regions,'' March 2014, available at http://www.eia.gov/petroleum/drilling/pdf/dpr-full.pdf.
---------------------------------------------------------------------------
Declines in air quality in states such as Wyoming and Utah have
been attributed to oil and natural gas development. In a technical
support document for its ozone nonattainment designation recommendation
for the Upper Green River Basin, Wyoming indicated that oil and natural
gas development was a ``pertinent factor'' in ozone concentrations
found in Sublette County. In the Upper Green River Basin area, Wyoming
attributed 94 percent of VOC emissions and 60 percent of the
NOX emissions in that area to oil and natural gas sources,
and indicated that speciated data from elevated ozone events carried a
characteristic oil and natural gas signature.\21\
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\21\ Wyoming Dept. of Environmental Quality, ``State of Wyoming
Technical Support Document I For Recommended 8-Hour Ozone
Designation for the Upper Green River Basin, WY,'' March 2009,
available at http://www.epa.gov/groundlevelozone/designations/2008standards/rec/letters/08_WY_rec.pdf.
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Utah, which was ranked 11th in the nation in crude oil production
in December 2013 \22\ and 10th in the nation in natural gas marketed
production in 2012,\23\ has also experienced adverse air quality
impacts from growth in oil and natural gas development. In June 2010,
the Utah Department of Environmental Quality reported that 2009 winter-
time ozone levels in the Uinta Basin reached a high-hour value of 0.137
ppm, a level that is well above the level of the current 8-hour ozone
NAAQS of 0.075 ppm. They also reported that values of PM2.5
in the winters of 2007, 2008, and 2009 were at concentrations at or
above the PM2.5 NAAQS.\24\ Beginning in the winter of 2012,
Utah undertook a multi-year, comprehensive study of emissions in the
Uinta Basin, including areas of the Uintah and Ouray Indian
Reservation. Based on data collected during the study, Utah concluded
that 98-99 percent of VOC emissions and 57-61 percent of NOX
emissions in the area originated from oil and natural gas
operations.\25\
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\22\ U.S. Energy Information Administration, ``Rankings: Crude
Oil Production,'' Dec. 2013, available at http://www.eia.gov/state/rankings/?sid=US#/series/46.
\23\ U.S. Energy Information Administration, ``Rankings: Natural
Gas Marketed Production,'' 2012, available at http://www.eia.gov/state/rankings/?sid=US#/series/47.
\24\ See Utah Dept. of Environmental Quality, ``Rural Air
Quality and Oil/Gas in Utah Fact Sheet,'' June 2010, available at
http://www.tricountyhealth.com/June2010-%20Air%20Issues%20with%20Oil%20and%20Gas.pdf.
\25\ See Utah Dept. of Environmental Quality, ``Ozone in the
Uintah Basin,'' Sept. 2013, available at http://www.deq.utah.gov/locations/uintahbasin/docs/2013/09Sep/ozone2013.pdf.
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In the United States, 418 counties are entirely or partly Indian
country.\26\ Table 1 summarizes the current status (as of August 2013)
of existing air quality designations and design values (DVs) (2010-
2012) of counties that are entirely or partly Indian country.\27\ It
includes information for the 8-hour 2008 ozone NAAQS, the 1997
PM2.5 annual NAAQS,\28\ 2006 PM2.5 24-hour NAAQS
and the 1987 PM10 NAAQS. Although the total percentage of
counties in Indian country which are known to be exceeding the NAAQS is
not large, the potential exists for others to exceed the NAAQS as oil
and natural gas production activities continue to grow.
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\26\ Limitations of use: The EPA makes no claims regarding the
accuracy or precision of data concerning Indian Country locations or
boundaries on the EnviroFacts Web site (http://www.epa.gov/enviro/).
The EPA has simply attempted to collect certain readily available
information relating to Indian Country locations. Questions
concerning data should be referred to the originating program or
Agency which can be identified in the EnviroFacts tribal query
metadata files for tribal areas in the lower 48 states (https://edg.epa.gov/metadata/rest/document?id=%7B8077CD55-74FB-4107-8047-3DEC0D55966A%7D&xsl=metadata_to_html_full), Alaska Reservations
(https://edg.epa.gov/metadata/rest/document?id=%7BE37B0B2-EB0B-436C-B993-C18D8895E522%7D&xsl=metadata_to_html_full), Alaska Native
Villages (https://edg.epa.gov/metadata/rest/document?id=%7BE4341D1B-656F-4E76-86DB-9216E8A968EA%7D&xsl=metadata_to_html_full), or
Alaska Native Allotments (https://edg.epa.gov/metadata/rest/document?id=%7B15FEB09B-752E-4B48-B01BD9F2D360623A%7D&xsl=metadata_to_html_full). The Indian Country locations shown in these files
are suitable only for general spatial reference and do not
necessarily reflect the EPA's position on any Indian Country
locations or boundaries or the land status of any specific location.
The inclusion of Indian Country information on the EnviroFacts Web
site does not represent any final EPA action addressing Indian
Country locations or boundaries. This information cannot be relied
upon to create any rights, substantive or procedural, enforceable by
any party in litigation with the United States or third parties. The
EPA reserves the right to change information on EnviroFacts at any
time without public notice. The EPA uses the U.S. Census Bureau 2010
tribal boundary layer data when developing environmental data query
responses for tribes in the lower 48 United States and information
from the Bureau of Land Management Alaska State Office when
developing environmental data query responses for tribes in Alaska.
The tribal boundary locations identified are suitable only for
general spatial reference and do not necessarily reflect the EPA's
position on any Indian Country locations or boundaries, or the land
status of any specific location. The EPA seeks to use the best
available national Federal data and may refine the tribal boundary
layer in the future as more accurate national Federal data become
available.
\27\ Information for those NAAQS for which the EPA has
designated nonattainment areas in Indian Country are available
online at http://www.epa.gov/air/tribal/tribalnsr.html and Docket ID
No. EPA-HQ-OAR-2011-0151. NAAQS for which the EPA has designated
nonattainment areas in Indian Country are: ozone (2008 NAAQS),
PM10 (1987 NAAQS), PM2.5 24-Hour (2006 NAAQS),
and PM2.5 annual (1997 NAAQS). No tribal lands are
currently designated nonattainment for SO2 (2010 NAAQS),
NO2, lead (2008 NAAQS), or CO.
\28\ Designations under the 2012 PM2.5 annual
standard (12.0 [micro]g/m\3\) have not yet occurred.
Table 1--The Current Status of Designations and DVs (2010-2012) of Counties That Are Entirely or Partly Indian
Country
----------------------------------------------------------------------------------------------------------------
Counties where
Counties where Indian country
Counties where Indian country exists and that
Designation Indian country and 2010-12 DVs are exceeding
exists exist NAAQS based on
2010-12 DVs
----------------------------------------------------------------------------------------------------------------
1997 PM[ihel2].[ihel5] Annual NAAQS:
Unclassifiable/Attainment.......................... 411 72 2
Maintenance........................................ 1 1 0
Nonattainment...................................... 6 6 6
--------------------------------------------------------
Totals......................................... 418 79 8
--------------------------------------------------------
2006 PM[ihel2].[ihel5] 24 Hour NAAQS:
Unclassifiable/Attainment.......................... 400 63 0
Maintenance........................................ 1 1 0
[[Page 32511]]
Nonattainment...................................... 17 16 6
--------------------------------------------------------
Totals......................................... 418 80 6
--------------------------------------------------------
2008 Ozone NAAQS:
Unclassifiable/Attainment.......................... 395 100 18
Unclassifiable..................................... 2
Nonattainment...................................... 21 21 18
--------------------------------------------------------
Totals......................................... 418 121 36
--------------------------------------------------------
1987 PM[ihel1][ihel0] NAAQS:
Unclassifiable/Attainment.......................... 384 35 3
Maintenance........................................ 13 4 1
Both Nonattainment and Maintenance Areas........... 6 5 2
Nonattainment...................................... 15 13 8
--------------------------------------------------------
Totals......................................... 418 57 14
----------------------------------------------------------------------------------------------------------------
A map displaying the areas of Indian country for which we have
ozone and PM2.5 monitors is available in the docket for this
ANPR (EPA-HQ-OAR-2011-0151), which is available at www.regulations.gov.
As shown by the map, a number of areas of Indian country lack a robust
monitoring network for these pollutants. Consequently, there are
uncertainties about the extent of environmental impacts from oil and
natural gas production in Indian country. Given the environmental
impacts from oil and natural gas production in various states, as
discussed above, air quality in Indian country may likewise be at risk
of reaching unhealthy levels due to impacts from oil and natural gas
production in Indian country.
2. Efforts To Improve Oil and Natural Gas Production Emissions and
Other Data
The EPA is working to improve our understanding of emissions from
oil and natural gas generating activity. We recently developed an Oil
and Gas Emission Estimation Tool that uses a methodology designed to
estimate county-level emissions for the oil and natural gas production
sector.\29\ Tool development started in April 2012 and has been
performed in collaboration with a national workgroup, which includes
state and regional emissions inventory developers. The draft tool
produces county-level emissions estimates for many of the processes
associated with oil and natural gas exploration and production for
calendar year 2011. For criteria pollutants and hazardous air
pollutants (HAP), this methodology is being used by the EPA to estimate
emissions for use in the National Emissions Inventory (NEI) for field
exploration, production, and gathering activities. The tool allows for
subtracting out point source emissions from the tool's nonpoint source
emission estimates to avoid double counted emissions. The tool
estimates emissions from the following oil and natural gas production
processes:
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\29\ A description of the tool, how it was developed, and its
intended use is available at http://www.epa.gov/ttn/chief/net/2011inventory.html under ``2011 NEI Version 1 Documentation,'' see
Nonpoint Emission Tools and Methods.
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Drill rigs;
Workover rigs;
Well completions (flaring/venting for both conventional and green
completions);
Well hydraulic fracturing and completion engines;
Heaters (separator, line, tank, reboilers);
Storage tanks (condensate, black oil, produced water);
Mud degassing;
Dehydration units;
Pneumatics (pumps, all other devices);
Well venting/blow downs (liquid unloading);
Fugitives;
Truck loading;
Wellhead engines;
Pipeline compressor engines;
Flaring;
Artificial lifts; and
Gas actuated pumps.
In addition, we recently completed a draft estimate of emissions
from oil and natural gas production activity in Indian country (except
for Alaska).\30\ The analysis uses outputs from the Oil and Natural Gas
Emissions Estimation Tool, as well as point source data submitted by
states and tribes to the 2011 NEI. Because tribes have only submitted
limited oil and natural gas emissions data to the NEI, we have
developed a methodology that relies heavily on state-submitted data to
develop draft emissions estimates for sources in Indian country. We
welcome feedback on our analysis and its assumptions and how to
continue to improve these estimates in the future.
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\30\ The draft analysis is available in the docket for this
ANPR, EPA-HQ-OAR-2011-0151, www.regulations.gov. The analysis does
not include an estimate of the emissions that may occur for tribal
lands adjacent to Alaska because the underlying spatial allocation
done for the county-based data is not readily available for Alaska.
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Also, the EPA's Greenhouse Gas Reporting Program, which was
required by Congress in the FY2008 Consolidated Appropriations Act,
collects activity and emissions data annually from petroleum and
natural gas systems facilities that are above the 25,000 metric ton
carbon dioxide equivalent reporting threshold. The data are reported by
facilities located across the United States, including facilities that
operate in areas of Indian Country.
Further, due to the cooperative efforts of states, the oil and
natural gas industry, multi-state organizations (e.g., Central States
Air Resources Agencies
[[Page 32512]]
(CenSARA) and WRAP) and environmental organizations, improvements have
been made in the development of emissions estimation methodologies and
in the submission of data to the 2011 NEI. These efforts have
substantially improved the quantity and quality of state emissions
information in the inventory, and, to a lesser but still helpful
extent, Indian country emissions information. This increase in
information has improved our understanding of the emissions impacts of
the oil and natural gas exploration and production sector. The
following summary describes some of these efforts.
EPA Region 8: In 2008, the EPA's Region 8 Office (for Montana,
North and South Dakota, Wyoming, Colorado, and Utah) assessed the
environmental impacts of oil and natural gas production in that region,
including areas of Indian country. The assessment concluded that VOC
emissions from activities associated with oil and natural gas
production comprised over 40 percent of the total criteria pollutant
emissions in the EPA Region 8 states in 2002, while emissions of
NOX, CO and SO2 contributed approximately 15
percent, 9 percent and 4 percent of total criteria pollutant emissions
in the Region, respectively. While the study found that PM emissions
from oil and natural gas production activity constituted a
comparatively small fraction of total regional criteria pollutant
emissions, the study, nonetheless, expressed concern about the
potential impacts of PM emissions from this sector in the future given
expected industry growth rates.\31\
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\31\ U.S. EPA Region 8, ``An Assessment of the Environmental
Implications of Oil and Gas Production: A Regional Case Study,''
Working Draft, Sept. 2008, available at http://www.epa.gov/sectors/pdf/oil-gas-report.pdf.
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Texas: While there are limited areas of Indian country in Texas,
information about the emissions from oil and natural gas production in
the State may be indicative of the types of emissions in certain areas
of Indian country. In 2010, Texas released a comprehensive report
characterizing emissions from oil and natural gas production in the
State. The report concluded that emissions from ``area source oil and
gas production sites on a state-wide basis are significant with over
200,000 tons of NOX, 1,500,000 tons of VOC, and 30,000 tons
of HAP emitted in 2008.'' \32\ Even larger contributions of VOC
emissions originated from storage tanks and pneumatic pumps. The report
indicated that compressor engines and artificial lift engines were the
main sources of NOX emissions.\33\
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\32\ M Pring, D. Hudson, J. Renzaglia, B. Smith and S. Treimel,
Eastern Research Group, Inc., ``Characterization of Oil and Gas
Production Equipment and Develop a Methodology to Estimate Statewide
Emissions,'' final report for Texas Commission on Environmental
Quality, Air Quality Division, Nov. 24, 2010, available at http://www.tceq.texas.gov/assets/public/implementation/air/am/contracts/reports/ei/5820784003FY1026-20101124-ergi-oilGasEmissionsInventory.pdf.
\33\ Id.
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WRAP: The WRAP began efforts to improve emissions estimation
methodologies and inventories in 2005. In Phase III and IV of its
study, WRAP developed a comprehensive base year inventory for several
basins in the Rocky Mountain area that encompass areas of Indian
country. The Phase III inventory showed that VOC emissions varied
widely between basins, with pneumatic devices, dehydrators, and tanks
being significant sources of VOC in non-coal methane basins. The
Williston Basin had significantly higher VOC emissions from oil and
natural gas activity than any other basin at over 350,000 tons/year.
Three other basins had VOC emissions that neared 100,000 tons/year.
The WRAP emissions inventory effort also found that emissions of
NOX per wellhead have remained relatively stable with
differences explainable by the amount of centralized versus well pad
compression used.\34\ Estimated emissions of SO2 were
comparatively less significant, and the predominant source of
SO2 emissions from oil and natural gas occurs downstream
from oil and natural gas production in gas processing plants.\35\
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\34\ A. Bar-Ilan, ENVIRON International Corp. and T. Moore,
WRAP/Western States Air Resources Council (WESTAR), ``Upstream Oil
and Gas Emission Inventories: Regulatory and Technical
Considerations,'' Oct. 21, 2013, available at http://www.wrapair2.org/pdf/Moore_Barilan_OandG_Inventories_10_20_13.pdf.
\35\ L. Gribovicz, WRAP, ``Analysis of States' and EPA Oil & Gas
Air Emissions Control Requirements for Selected Basins in the
Western United States (2013 Update), Nov. 8, 2013, available at
http://www.wrapair2.org/Analysis.aspx.
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In July 2011, the WRAP published the first emissions inventory
report that attempts to quantify the contribution of oil and natural
gas mobile source emissions to total emissions inventories. Results of
this limited study showed that mobile sources did not contribute
significantly to total VOC, CO, and NOX emissions, but did
comprise a significant proportion of total PM10 emissions
due to vehicle traffic on unpaved roads.\36\
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\36\ A. Bar-Ilan, J. Grant, R. Parikh, R. Morris, ENVIRON
International Corp. and D. Henderer, Kleinfelder/Buys and Assos.,
``Oil and Gas Mobile Sources Pilot Study,'' U.S. EPA work assignment
report 4-08, July 2011, available at http://www.wrapair2.org/pdf/2011-07_P3%20Study%20Report%20(Final%20July-2011).pdf.
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CenSARA: In 2012, CenSARA released an oil and natural gas emissions
study that included such area source emission points as hydraulic
fracturing pumps, casing gas venting, produced water storage tanks,
gas-actuated pneumatic pumps, fugitive emissions from compressor seals,
mud degassing, and hydrocarbon liquids loading. Emissions estimates for
these sources, however, contain some uncertainties due to data gaps on
equipment usage and size, local gas compositions, usage of control
methods, and venting rates for particular sources. The CenSARA study
concluded that major sources of VOC emissions vary greatly by basin,
and that pneumatic devices and storage tank emissions consistently
remained significant sources of VOC emissions in all basins. For
NOX emissions, the report identified wellhead compressor
engines as the ``largest source of NOX emissions across the
CenSARA domain, representing on average at least 50 percent of the
total basin-level NOX emissions in some of the basins such
as Permian, Western Gulf, Anadarko, Bend Arch Fort Worth and East
Texas.'' The report also identified heaters as a major source of
NOX emissions, especially in oil producing basins. Notably,
the report did not specifically highlight NOX emissions from
flaring, but instead included these emissions within its estimates for
different source types such as well completions, condensate tanks,
crude oil tanks, blow downs and dehydrators.\37\
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\37\ ENVIRON and Eastern Research Group, Inc., prepared for
CenSARA, ``2011 Oil and Gas Emission Inventory Enhancement Project
for CenSARA States,'' Dec. 21, 2012, available at: www.censara.org/html/presentations.php? mode=download&id=200.
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Efforts to improve emission estimation and measurement
methodologies and characterize air quality impacts from oil and natural
gas production operations are ongoing. While the quantity and quality
of our NOX and VOC inventories are getting better, we cannot
combine prior and current information to form emission trends for oil
and natural gas production because of the lack of quality data
regarding these sources in earlier inventories. Also, non-ozone
precursors and other criteria pollutants are not as well studied and
characterized, although the WRAP emissions inventory project suggests
that the primary source of SO2 emissions is natural gas
processing plants.\38\
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\38\ L. Gribovicz, WRAP, ``Analysis of States' and EPA Oil & Gas
Air Emissions Control Requirements for Selected Basins in the
Western United States (2013 Update),'' Nov. 8, 2013, available at
http://www.wrapair2.org/Analysis.aspx.
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[[Page 32513]]
We also recognize that VOC emissions information from sources
located within one geological formation may not be representative of
the type of emissions expected from other formations. Different
geological formations produce different types of fluids and gases which
affect the pollutant concentrations in emissions from those gases and
liquids. VOC emissions rates at a single well tend to decline after the
time the well is drilled and becomes productive. These rates can also
change due to operational variances resulting from declines in flow
rates and temperature fluctuations. Pollutant concentrations from the
same well site also change as production draws liquids and gas from
deeper within the formation.
3. Summary Conclusions on the State of Oil and Natural Gas Production
Emissions and Associated Air Quality Information in Indian Country
When the Agency reviews the information available to characterize
the emissions impact of ongoing oil and natural gas production activity
in Indian country, we reach two main conclusions. First, we recognize
the need to continue improving our understanding of oil and natural gas
production emissions and activity in Indian country. Second, despite
the need for additional information and associated uncertainties, we
believe enough information is available that it is appropriate to seek
comment on the need to establish requirements for existing sources to
protect air resources and public health in Indian country from the
impacts of oil and natural gas production activity, especially in cases
where adjoining state requirements address existing sources in those
states. Available evidence indicates that cumulative emissions from
existing sources in the oil and natural gas production industry are
causing elevated ambient ozone levels in areas outside of Indian
country. We believe that air quality in Indian country may be similarly
at risk of reaching unhealthy levels from the cumulative impacts of oil
and natural gas production sources. Although at this time, we cannot
quantify the magnitude of that risk, we believe that there is the
possibility that air quality levels may violate the 8-hour ozone NAAQS
in some areas currently classified as unclassifiable/attainment, and
also may cause increases in ozone concentrations in areas already
violating the 8-hour ozone NAAQS.
This second conclusion is based on best available information on
oil and gas emissions and associated air quality, including: Data
provided to EPA through efforts led by individual states or multi-state
organizations to improve our understanding of oil and natural gas
emissions and associated air quality information for areas with oil and
natural gas production operations; state emissions inventories for, and
studies of, the oil and natural gas production industry that provide us
with information on the predominant sources of VOC and NOX
emissions in the oil and natural gas sector; and state and EPA
regulatory efforts \39\ to control emissions from new and existing
sources in the oil and natural gas industry that indicate that cost-
effective emissions reductions are likely available to control
emissions from these VOC and NOX emissions sources. Given
these factors, we believe it is appropriate to seek comment on
regulating existing oil and natural gas production emission sources, as
well as new and modified minor sources and minor modifications at major
sources located in Indian country through a FIP or other approach to
ensure air quality resources are protected in Indian country.
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\39\ See, e.g., L. Gribovicz, WRAP, ``Analysis of States' and
EPA Oil & Gas Air Emissions Control Requirements for Selected Basins
in the Western United States (2013 Update),'' Nov. 8, 2013,
available at http://www.wrapair2.org/Analysis.aspx; NSPS 40 CFR Part
60, Subpart OOOO; and B. Finley, Denver Post, ``Colorado takes up
details in push to cut oil and gas air pollution,'' Nov. 22, 2013,
available at http://www.denverpost.com/environment/ci_24575958/colorado-takes-up-details-push-cut-oil-and.
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V. Federal Implementation Plan Approach
A. What is a FIP?
Under section 302(y) of the Act, the term ``Federal implementation
plan'' means ``. . . a plan (or portion thereof) promulgated by the
Administrator to fill all or a portion of a gap or otherwise correct
all or a portion of an inadequacy in a State implementation plan, and
which includes enforceable emission limitations or other control
measures, means or techniques (including economic incentives, such as
marketable permits or auctions of emissions allowances), and provides
for attainment of the relevant national ambient air quality standard.''
42 U.S.C. 7602.
While the definition refers only to an inadequacy in a state plan,
we also use this term to describe actions we take to regulate emissions
in Indian country pursuant to our authority under CAA section 301(d)
which authorizes us to treat Indian tribes as states and, in
appropriate circumstances, to issue regulations establishing applicable
requirements. 42 U.S.C. 7601(d).
The Indian country minor NSR rule is an example of a FIP. In that
rule, we identified a regulatory gap that could have the effect of
adversely impacting air quality due to the lack of approved minor NSR
permit programs to regulate construction of new and modified minor
sources and minor modifications of major sources in Indian country. The
EPA promulgated the FIP to ensure that air resources in Indian county
are protected by establishing a preconstruction permitting program to
regulate emissions increases resulting from construction and
modification activities that are not already regulated by the major NSR
permitting programs.
B. What is the EPA's authority for issuing a FIP regulating sources in
Indian country?
Section 301(d) of the CAA, 42 U.S.C. 7601(d), directs us to
promulgate regulations specifying the provisions of the Act for which
it is appropriate for us to treat Indian tribes in the same manner as
states. Pursuant to this statutory directive, the EPA promulgated
regulations entitled ``Indian Tribes: Air Quality Planning and
Management'' [Tribal Air Rule (TAR)] 63 FR 7254 (February 12, 1998).
This regulation delineates the CAA provisions for which we will treat
tribes in the same manner as states. See 40 CFR 49.3, 49.4. In this
regulation, we determined that we would not treat tribes as states with
respect to CAA section 110(a)(1) (State Implementation Plan (SIP)
submittal) and CAA section 110(c)(1) (directing the EPA to promulgate a
FIP ``within 2 years'' after we find that a state has failed to submit
a required plan, or has submitted an incomplete plan, or within 2 years
after we disapproved all or a portion of a plan), among other
provisions. See 40 CFR 49.4(a), (d); 63 FR at 7262-66 (February 12,
1998).
The TAR preamble clarified that by including CAA section 110(c)(1)
on the Sec. 49.4 list, ``EPA is not relieved of its general obligation
under the CAA to ensure the protection of air quality throughout the
nation, including throughout Indian country. In the absence of an
express statutory requirement, EPA may act to protect air quality
pursuant to its `gap-filling' authority under the Act as a whole. See,
e.g. CAA section 301(a).'' 63 FR at 7265, Feb. 12, 1998. The preamble
confirmed that ``EPA will continue to be subject to the basic
requirement to issue a FIP for affected tribal areas within some
[[Page 32514]]
reasonable time.'' Id. (referencing Sec. 49.11(a) which provides that
the Agency will promulgate a FIP as necessary or appropriate to protect
tribal air quality within a reasonable time if tribal efforts do not
result in adoption and approval of tribal plans or programs).\40\
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\40\ 40 CFR 49.11(a) states that the EPA ``[s]hall promulgate
without unreasonable delay such Federal implementation plan
provisions as are necessary or appropriate to protect air quality,
consistent with the provisions of sections 301(a) and 301(d)(4), if
a tribe does not submit a tribal implementation plan meeting the
completeness criteria of 40 CFR part 51, appendix V, or does not
receive EPA approval of a submitted tribal implementation plan.''
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The preamble to the TAR also set forth our view that, based on the
``general purpose and scope of the CAA, the requirements of which apply
nationally, and on the specific language of sections 301(a) and
301(d)(4), Congress intended to give to the Agency broad authority to
protect tribal air resources.'' Id. at 7262. It further discussed the
EPA's intent to ``use its authority under the CAA `to protect air
quality throughout Indian Country' by directly implementing the Act's
requirements in instances where tribes choose not to develop a program,
fail to adopt an adequate program or fail to adequately implement an
air program.'' Id.
In this action, we are soliciting comment on the concept of using a
FIP to regulate new and modified emissions units at facilities in the
oil and natural gas production segment that operate in Indian country.
Additionally, we are soliciting comments on whether a FIP, if that is
determined to be an appropriate permitting approach for new oil and
natural gas production sources, should also be used to regulate
existing sources. If we determine that it is ``necessary or
appropriate'' to exercise our discretionary authority under sections
301(a) and 301(d)(4) of the CAA and 40 CFR 49.11(a) of our implementing
regulations, we will publish a proposed rule that provides an
opportunity for full public review and comment.
The EPA has already promulgated a FIP regulating new, modified and
existing oil and natural gas production operations \41\ on the Fort
Berthold Indian Reservation (78 FR 17836, March 22, 2013). The FIP
requires owners and operators of new, modified and existing oil and
natural gas production facilities to reduce VOC emissions from certain
equipment. The rule is aimed at addressing significant emissions of VOC
that could potentially threaten public health and the environment,
while minimizing the regulatory burden (i.e., under the FIP, there is
no source-by-source review of permit applications) and disruption to
economic development on the reservation. The rule also provides
improved consistency between what oil and natural gas production
sources located on the reservation must do to control emissions and the
requirements applicable to oil and natural gas production sources
located on neighboring lands within State jurisdiction in North Dakota.
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\41\ The FIP defined existing sources as sources constructed or
modified on or after August 12, 2007 but before April 22, 2013
(April 22, 2013 is the effective date of the FIP). Sources
constructed or modified on or after April 22, 2013 are new and
modified under the FIP.
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C. Would an oil and natural gas FIP apply in addition to the Indian
Country Minor NSR permitting program and would compliance with the FIP
be mandatory?
We envision that a source that complies with appropriate
requirements for construction and modification under the FIP would not
cause or contribute to a NAAQS or increment violation. Accordingly, the
oil and natural gas FIP would serve the purpose for which the EPA
promulgated the Indian Country Minor NSR permitting program, and, thus,
it would be unnecessary to require a facility complying with the
requirements for modification and construction activities in the FIP to
also comply with requirements in the Indian Country Minor NSR
permitting program.
The Indian Country Minor NSR permitting program established general
requirements to regulate construction and modification of minor sources
and minor modifications at major sources from all types of pollutant-
emitting source categories. Because a FIP would establish requirements
tailored only for facilities in the oil and natural gas production
segment, the EPA could specify control technology requirements that
ensure that emissions increases from construction or modification of a
minor source or minor modifications of a major source would not cause
or contribute to a NAAQS or increment violation. In Section VII.A., we
request comment on how we might coordinate compliance between the two
programs if we were to pursue a FIP approach.
D. Could a FIP be used to satisfy major source NSR requirements?
A FIP would not replace the requirement for major sources to obtain
a preconstruction permit and comply with Best Available Control
Technology (BACT) emission limitations (in attainment and
unclassifiable areas) or Lowest Achievable Emission Rates (LAER) (in
nonattainment areas) before beginning actual construction of a new
major source, or undertaking a major modification. However, if the
enforceable requirements of the FIP limited the potential to emit of a
new major source or the emissions increase of a major source undergoing
a modification to less than major source levels, those sources could
avoid the requirements for new major sources or major modifications.
Both sections 165 and 172 of the CAA explicitly require major sources
to obtain permits for the construction and operation of new or modified
major stationary sources. 42 U.S.C. 7475 and 7502. We have already
promulgated FIPs to carry out the major source permitting requirements
of the Act for these areas (40 CFR 49.166-49.173, 52.21, and 52.24).
An oil and natural gas production FIP for minor sources, or minor
modifications at major sources, could assist in providing a more
streamlined major NSR permit issuance process in the event a new major
source locates in Indian country, or an existing source undergoes a
major modification. This likely could occur if the emissions controls
required in the FIP were subsequently determined to constitute BACT or
LAER controls, or because the emission reductions from the FIP help
preserve the PSD increment in a given area. The development of the FIP
will also provide interested parties the opportunity for full comment
and review of the regulatory provisions.
VI. General Permit Approach
A. What is a general permit?
Under a CAA general permit approach, the EPA would use its
permitting authority, established pursuant to 40 CFR 49.156, to issue a
permit document (i.e., a general permit) that contains emissions
limitations, monitoring, recordkeeping, and reporting requirements for
a particular category of sources. The general permit would address
emissions from new and modified units at the permitted source. To
obtain coverage under the general permit, a minor source would submit
an application for coverage to the reviewing authority. The application
would demonstrate that the source qualifies as part of the relevant
source category and also contains information on the nature of the
construction or modification activity, including the type of sources
involved and the magnitude of the proposed emissions increase. The
reviewing authority would review the application once it was complete
to verify that the source qualifies for coverage under the general
permit and that it can meet the requirements of the
[[Page 32515]]
permit. Following this review period, which includes the opportunity
for the public to comment on the appropriateness of a source receiving
coverage under a general permit, the reviewing authority would issue a
notice of approval or would deny the request for coverage. This process
can take as long as 90 days. The public would have an opportunity to
comment on the terms and conditions of the general permit itself that
would apply to the sources gaining coverage under the permit only
during the time the EPA is developing the permit and within that
process. Once the EPA issues the permit, the public may only challenge
whether a particular source qualifies for coverage under the
established permit.
B. How would a general permit compare to a FIP?
As discussed previously, although NSR general permits cannot be
used to address existing sources, a FIP could extend to existing
sources; this is a key distinction between general permits versus a
FIP.
Another distinction between a general permit and a FIP relates to
the ability of the public to comment on and appeal a source's
commencement of construction. To inform the public of the proposed
construction project under a general permit or a FIP, we envision that
the process could require the reviewing authority to make the source's
advance notice available to the public, probably by posting it on the
internet. Unlike the procedures for issuing and appealing a general
permit, however, there would be no process for a citizen to comment on
or appeal the right of a source to begin construction under the
authority of an oil and natural gas production FIP. Nonetheless, an oil
and natural gas production FIP would require a source to meet emission
control requirements intended to avoid an increase in emissions that
could cause or contribute to a NAAQS or PSD increment violation.
With respect to compliance and enforcement, the EPA (or a tribe
with implementing authority) would be responsible for compliance and
enforcement on a regular basis. In addition, any citizen could enforce
the provisions of a general permit or a FIP, as it would the
requirements of any other implementation plan or CAA requirement by
commencing a civil action in the district court in the judicial
district in which the source is located. Citizens retain the right
under CAA section 304(a)(1) to commence a civil action ``against any
person . . . who is alleged to have violated . . . or to be in
violation of (A) an emission standard or limitation under this [Act]. .
. .'' 42 U.S.C. 7604(a)(1). The Administrator also would retain the
ability to enforce the requirements of a FIP under section 113(a)(1) of
the Act, and in some cases, section 167 of the Act. 42 U.S.C. 7413 and
7477.
Both a general permit and an oil and natural gas production FIP
provide a more streamlined approach for authorizing construction and
modification of a source compared to site-specific permitting. Because
an oil and natural gas production FIP would not require a source to
initiate advance review and approval of coverage from the reviewing
authority (similar to a permit by rule approach), it would reduce the
resource burden on reviewing authorities associated with processing the
potentially large volume of requests from true minor sources in the oil
and natural gas production segment for coverage under a general permit.
However, a FIP would provide less upfront scrutiny of an individual
construction or modification project, and, unlike under a general
permit, a citizen would not have the ability to object to a permit or a
specific project gaining coverage and proceeding with construction
under a FIP. The FIP would rely on the overall strength of the
emissions control requirements and the compliance monitoring and
reporting provisions (including potentially regulating both new and
existing emissions generating activities) in the FIP to ensure that a
new or modified source does not cause or contribute to a NAAQS or PSD
increment violation.
Unlike a site-specific permit, both a general permit and a FIP
would require a pre-defined, standardized level of control that would
not provide flexibility to adapt applicable requirements to the
specific needs of individual areas of Indian country. A FIP could,
however, be designed to address such needs in a broad way by requiring
differing levels of control in areas with differing air quality
concerns. Under the Indian Country Minor NSR rule, a reviewing
authority could deny a source's request for coverage under the general
permit and instead issue a site-specific permit to address the unique
needs of the area or source. This option can be available if we retain
applicability of the Indian Country Minor NSR rule and use the FIP only
as an optional, alternative mechanism. (See Section VII.A.)
One potential advantage of not retaining an option for site-
specific permitting along with the FIP (discussed in Section VII.F.) is
that regulated sources operating throughout Indian country would be
subject to a ``level playing field,'' (i.e., all sources, or at least
those located in or planning to locate in areas with similar air
quality, would be subject to the same requirements). This would ensure
that all oil and natural gas production sources in areas of Indian
country with similar air quality are subject to the same level of
emissions control. Neither a FIP nor a general permit could guarantee a
``level playing field'' in relation to sources in surrounding areas
where states may have more or less stringent requirements than those
that apply under the FIP or general permit in Indian country. Another
approach would be for the FIP itself to provide a source the ability to
seek a site-specific limit through a site-specific permit or FIP. We
request comment on whether the inclusion of such a provision would be
advisable.
The EPA seeks comment on the advantages and disadvantages
associated with using a FIP approach versus a general permit approach
or other potential approaches such as a permit by rule that could be
taken to manage air quality impacts from oil and natural gas production
sources located in Indian country. We note that a permit by rule
approach and a FIP approach would function in much the same manner,
however a FIP could be used to address existing sources whereas an NSR
permit by rule would be limited to new and modified sources.
VII. Areas Where the EPA Is Requesting Comment
A. How would an oil and natural gas FIP or general permit relate to the
Indian Country Minor NSR rule?
We envision designing any proposed FIP or general permit such that
the emissions from a source that complies with the requirements for
construction and modification likely would be protective of the NAAQS.
Accordingly, we believe it is unnecessary to require a source to comply
with both programs (i.e., the FIP or general permit and the Indian
Country Minor NSR rule). We request comment on this approach.
In concert with promulgation of a FIP or issuance of a general
permit, we could amend the Indian Country Minor NSR permitting program
to provide a blanket exemption for all sources in the oil and natural
gas production segment subject to the FIP or general permit. As a
result, a minor source that constructs, or a minor or major source that
undertakes a minor modification in Indian country, would need to comply
only with the requirements in an oil and natural gas production FIP or
general
[[Page 32516]]
permit.\42\ Alternatively, we could exempt from the Indian Country
Minor NSR permitting program only those sources that choose to comply
with the requirements of an oil and natural gas production FIP or
general permit in lieu of going through the permitting process from the
minor NSR permitting program. This would mean that a source would have
an option of choosing which program to comply with: (1) The FIP or
general permit or (2) a site-specific alternative requirement. This may
be appropriate if a particular source faces unique circumstances and it
believes that permitting under a site-specific permit would result in
different control requirements than required under the FIP or general
permit. The resources required for reviewing and processing site-
specific permits could increase the resource burden on reviewing
authorities and thereby reduce some of the benefits of a FIP or general
permit, but would provide flexibility to the industry. It would also
increase the burden on the reviewing authorities as they would need to
do more checking on actual growth and changes in air quality because of
lack of full coverage of the FIP or general permit.
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\42\ A major source may also have certain recordkeeping/
reporting obligations under the reasonable possibility provisions of
the major source program.
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Under the first approach, all sources would be required to comply
with the oil and natural gas production FIP or general permit, and
would not be able to avail themselves of a site-specific permit. Non-
compliance with the FIP or general permit provisions could result in an
enforcement action. Under the second approach, a source would have to
specifically request coverage under the Indian Country Minor NSR
regulation, and failure to do so could result in an enforcement action.
We request comment on the best means for coordinating compliance
between a FIP or general permit and the Indian Country Minor NSR
permitting program, and whether we should allow individual sources a
choice as to the program with which they will comply.
B. Should we regulate existing emission units at a source under a FIP?
We are concerned that the rapid growth of the oil and natural gas
production segment in combination with existing exploration and
production activities could result, or in some cases already has
resulted, in adverse air quality impacts. We also believe that a number
of cost-effective emission reduction measures could be applied to
existing emissions units to balance new growth by mitigating the
potential for adverse air quality impacts from overall increases in
emissions. A number of state air pollution control agencies already
regulate some existing emissions from this segment.\43\ For example, in
February 2014 Colorado adopted additional regulations for oil and
natural gas production operations that include such requirements as
expanding nonattainment area pneumatic control requirements statewide
and reducing venting and flaring of gas streams at well sites, among
other control strategies.\44\ Colorado's proposed revisions indicate
that operators could install flares and controls on existing,
uncontrolled storage tank batteries with VOC emissions of 6 tons per
year (tpy) or higher at an average cost effectiveness value of $716 per
ton of VOC reduced, and could install flares on existing produced water
storage tanks with VOC emissions of 6 tpy or higher at an average cost
effectiveness value of $715 per ton of VOC reduced.\45\ In addition,
the regulations determined leak detection and repair monitoring to be
cost effective at oil and natural gas production facilities. Some
technologies may even provide the industry with cost savings due to
recovered product. For example, the EPA's Natural Gas Star program
estimates that adding a vapor recovery unit to a storage tank could pay
for itself in 3 to 37 months, and thereafter result in cost
savings.\46\
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\43\ See, e.g., L. Gribovicz, WRAP, ``Analysis of States' and
EPA Oil and Gas Air Emissions Control Requirements for Oil and Gas
Emissions Control Requirements for Selected Basins in the Western
United States (2013 Update),'' Nov. 8, 2013, available at http://www.wrapair2.org/pdf/2013-11x_O&G%20Analysis%20(master%20w%20State%20Changes%2011-08).pdf.
\44\ See Colorado Dept. of Public Health and Environment, Air
Quality Control Commission Web site at http://www.colorado.gov/cs/Satellite/CDPHE-AQCC/CBON/1251647985820.
\45\ Colorado Dept. of Public Health and Environment, Air
Quality Control Commission, ``Cost-Benefit Analysis Submitted Per
Sec. 24-4-103(2.5), C.R.S.,'' February 19, 2014, available at ftp://ft.dphe.state.co.us/apc/aqcc/COST%20BENEFIT%20ANALYSIS%20%26%20EXHIBITS/CDPHE%20Cost-Benefit%20Analysis_Final.pdf.
\46\ See ``Lessons Learned from Natural Gas STAR Partners;
Installing Vapor Recovery Units on Storage Tanks,'' available at
http://epa.gov/gasstar/documents/ll_final_vap.pdf on the EPA's
Natural Gas Star Web site: http://epa.gov/gasstar/index.html.
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In view of the availability of cost-effective emission reductions,
and the impact of these existing emission sources on air quality, we
are requesting comment on whether to require emission controls for
existing oil and natural gas production sources in Indian country to
create a growth margin that will allow further development in the oil
and natural gas production segment in a manner that is protective of
the environment. We are concerned about the impact existing sources
have already had on air quality in some areas of Indian country. The
EPA seeks comment on whether, if the EPA were to promulgate a FIP, the
FIP should impose control requirements on new and modified minor
sources and minor modifications at major sources, as well as on
existing sources. We also request comment on the specific emissions
units we should include or exclude in such a proposed regulation
addressing existing source emissions.
Some state air rules also contain setback requirements that ensure
that new oil and natural gas production activities occur outside a set
distance from certain types of structures, such as schools, hospitals
or residential dwellings. We request comment on the concept of
including a setback requirement in a FIP, as well as the distances we
might consider for any such setback requirement, and on the type of
structures for which a setback requirement might be appropriate.
Existing sources would not be addressed by a general permit or a
permit by rule for oil and natural gas sources locating in Indian
country because NSR general permits and permits by rule cannot apply to
existing sources given that the EPA's authority under the CAA new
source review provisions relates to new sources. If the EPA were to
develop a general permit or a permit by rule rather than a FIP to
manage emissions impacts in Indian country due to oil and natural gas
production activities, then we request comment on how could we best
ensure protection of the NAAQS.
C. Would a FIP or general permit apply uniformly or would the
requirements vary depending on a source's location?
The EPA is also interested in receiving comments on the question of
whether, if a FIP were promulgated or a general permit were issued, the
FIP or general permit should apply uniformly across all of Indian
country (including existing sources, regardless of whether they have
undergone modifications) or whether the requirements should vary
according to CAA designation status or based on other criteria.
In conjunction with considering whether we should regulate existing
emissions units in a national FIP or general permit, we will consider
whether we should create uniform standards that apply in all areas, or
have the requirements vary in different oil
[[Page 32517]]
and natural gas basins or air quality control regions. If we were to
vary the requirements depending on a source's location, we would
consider the areas of Indian country for which it may be appropriate or
necessary to regulate existing emissions units. Potential options for a
national FIP or general permit include:
1. Uniform requirements across all areas of Indian country;
2. Uniform requirements only in nonattainment areas for a
particular pollutant;
3. Uniform requirements in nonattainment areas and in certain
attainment areas that are approaching nonattainment based on an area's
design value(s);
4. Uniform requirements across oil and natural gas basins or air
quality control regions that exceed a certain density of well pad
sites;
5. Requirements that vary by basin based on air quality needs; or
6. Requirements that vary by basin based on information or
requirements from surrounding states.
In considering these options, we would consider factors such as the
resources and time necessary to develop and implement the standards, a
desire to foster a ``level playing field'' between sources located in
different areas, the availability and cost-effectiveness of various
control technologies, and our existing knowledge related to air quality
in different areas of Indian country.
In general, uniform standards that apply to all sources are less
complex to establish and implement than requirements that vary. If, in
a national FIP or general permit, we vary requirements in different oil
and natural gas basins or air quality control regions, then the rule
would likely take additional time to develop and implement. Compliance
would be correspondingly delayed and emissions reduction benefits
realized more slowly. Inconsistent regulations could also be more
difficult and complicated for the regulated community to understand and
comply with, especially for companies with operations in multiple
areas. In comparison, the benefits from uniform standards could be
realized sooner and the requirements could be more easily understood,
but uniform standards would need to ensure a sufficient level of
protection for all areas in which they would apply despite differences
in air quality issues in different areas.
During the comment period for the Indian Country Minor NSR rule, we
received comments suggesting that requiring a single set of controls
for all minor sources across Indian country does not provide the needed
flexibility to adapt regulations to the needs of individual areas of
Indian country or take into account the benefit of a ``level playing
field'' with surrounding areas. Conversely, other commenters expressed
concern that if a federal program varies requirements across Indian
country, then sources within certain areas of Indian country may be
placed at a competitive disadvantage compared to sources located in
other areas of Indian country. 76 FR 38748, 38760-61, July 1, 2011. For
example, if we regulate existing units at a source by mirroring
appropriate requirements found in surrounding state jurisdictions, then
many emission units at a source in the same area may be subject to
similar requirements, but sources in different areas of Indian country
would be subject to different requirements because the requirements can
vary from state to state. We request comment on the best manner for
considering or reconciling these opposing views in the context of
determining the manner, and the areas in which, we might regulate
existing emissions units.
Using design values or attainment status to identify areas in need
of enhanced environmental protection may yield results that are not
equitable and/or fully protective of air quality, due to the scarcity
of air monitoring in Indian country. For example, we might require more
stringent controls in a tribal area designated as nonattainment, while
an unmonitored unclassifiable/attainment area might be subject to
lesser controls.
We request comment on whether and how it would be appropriate to
use information from nearby states as a surrogate to address the lack
of air quality monitoring data in neighboring areas of Indian country.
This information could include actual air monitoring data, attainment
status based on actual monitoring data, or even oil and natural gas
regulatory provisions. Referencing state requirements as the basis for
requirements in surrounding areas under Federal jurisdiction is not
without precedent. In adopting requirements for sources locating on the
Outer Continental Shelf, Congress amended the CAA to add section 328,
which requires sources locating on the Outer Continental Shelf to
comply with requirements that apply on nearby state land in some
circumstances. We specifically request comments from tribal governing
bodies on the appropriateness of using state information or regulations
in this manner.
In sum, as we consider whether it is appropriate or necessary to
reduce emissions from existing emissions units in the oil and natural
gas production segment to balance new source growth with environmental
protection, we must also consider the appropriate scope of those
requirements in terms of the areas in which the requirements apply, the
stringency of the requirements, and the manner in which we might apply
them. We request comment on all aspects of this issue.
D. What applicability threshold should apply if we regulate existing
sources, and should we create exemptions?
If we regulate existing sources, then we would specify an
applicability threshold to identify which sources are subject to
control requirements. In the NSR permitting program, we distinguish
applicability of regulations to sources based on whether they are
``major'' versus ``minor.'' For example, under the provisions of the
PSD program, an oil and natural gas source located in an ozone
attainment or unclassifiable area would be a major source if it emits
or has the potential to emit (PTE) 250 tpy of any regulated pollutant.
Sources that are ``major'' are subject to permitting and emissions
control requirements, among other requirements. Certain minor sources
are subject to only recordkeeping requirements. Under the provisions of
the Indian Country Minor NSR permitting program, an oil and natural gas
source located in an ozone unclassifiable/attainment or unclassifiable
area would be a minor source if it emits or has the PTE below 250 tpy
of all regulated pollutants, but VOC or NOX above the minor
source regulatory thresholds for these pollutants. See 40 CFR 49.153.
Minor sources and major sources undergoing minor modifications must
comply with the provisions of the Indian Country Minor NSR permitting
program, while sources with a PTE that is less than the regulatory
threshold are exempt from the rule.
In regulating emissions from existing emission units at a source,
we could incorporate these commonly understood regulatory thresholds in
a number of ways. We could apply requirements to only existing major
sources, as defined under the NSR program. Alternatively, we could
apply the requirements to both major and minor existing sources. If we
apply requirements to both minor and major sources, then we would have
to determine whether the regulations would regulate these sources
equally, or whether we would establish different requirements based on
the size of the source. We request comment on whether following a
traditional applicability approach that would make a distinction
between ``major'' or ``minor'' source is a desirable way to
[[Page 32518]]
manage air quality from oil and natural gas production sources in
Indian country and, if so, then at which existing sources should we
impose control requirements. We also seek comment on what specific
pieces of oil and natural gas production equipment should be regulated,
and how and to what degree.
In considering this issue, it is prudent to take into account the
potential air quality impacts from oil and natural gas production
activities. As explained in Section IV.B., the oil and natural gas
production industry is comprised of numerous, geographically dispersed
emissions points. The contribution of any individual emission point to
the total emissions inventory may be comparatively small. But,
collectively, the cumulative emissions of numerous existing emissions
points could exceed that of large, new major sources, and result in
adverse air quality impacts. If we were to regulate emissions only from
existing major sources, then we would be ignoring the cumulative air
quality impacts from existing minor sources. Regulating existing
emissions units at both major and minor sources (or at some lower
level) would afford the greatest level of environmental protection and,
if sufficiently controlled, would create more room for growth.
Another consideration relates to the complexity of making
stationary source determinations. Determining whether one or more
emissions points are part of the same stationary source can require an
owner or operator, as well as the permitting authority, to undertake an
in-depth analysis of the inter-relationships between two or more
emissions points.\47\ It is not uncommon for disputes to arise
regarding the boundaries of a stationary source, whether the source
qualifies as a ``minor'' or ``major'' source, and where a source's
actual or potential emissions stand with respect to the minor source
PTE thresholds.
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\47\ The exact nature of the analysis required and the specific
sources of emissions that must undertake that analysis has been a
topic of recent litigation. See Summit Petroleum v. EPA, 690 F.3d
733 (6th Cir. 2012) and National Environmental Development
Association's Clean Air Project v. EPA, No. 13.1035 (D.C. Cir.). To
the extent the source determination requirements change as a result
of this litigation, either as a general matter or with specific
regard to application to oil and gas emissions, EPA will address
those changes in future actions related to this ANPR.
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Rather than following traditional permitting tons per year
applicability thresholds in determining what sources to regulate and
how to regulate them, we could identify cost-effective emissions
reduction strategies and apply these requirements regardless of the
cumulative total emissions from any given stationary source.
Nevertheless, sources that are subject to major source NSR and/or Title
V would still need to comply with those requirements. By applying
emissions reduction measures without regard to cumulative emissions
from each source, we could ensure that all existing sources meet cost-
effective emissions reduction requirements, and avoid potential
disputes related to stationary source boundaries. We request comment on
using such an approach for establishing emission control requirements
for existing sources, in lieu of following a traditional approach that
distinguishes sources based on their size. Such an approach would be
consistent with control requirements established in the majority of New
Source Performance Standards (NSPS) and could incorporate unit specific
size thresholds.
We are also seeking comment on whether we should include certain
exemptions within the applicability provisions of any potential FIP to
prevent regulatory redundancy. For example, should we exempt any
emissions producing activity or emissions unit at a source that might
otherwise be required to comply with requirements in a FIP, if we
already require control of emissions from that activity or emissions
unit under a Federal NSPS or a National Emissions Standard for
Hazardous Air Pollutants (NESHAP) (77 FR 49490, Aug. 16, 2012) that has
either the goal or effect of reducing criteria pollutant emissions? The
Oil and Gas Sector NSPS and NESHAP apply nationally, including in
Indian country, but the requirements in a FIP could go beyond those in
the NSPS or NESHAP, if it is deemed necessary. This is similar to the
approach in minor source NSR programs in some states.
Another question we would consider is whether we should exempt
existing emissions units at a source that obtained a major NSR permit
within some recent time period if they are complying with BACT or LAER
for a particular pollutant. If so, then how far in the past should we
recognize BACT or LAER requirements? Are there other regulatory
provisions with which oil and natural gas sources must comply that we
should consider when crafting the applicability provisions of a
potential oil and natural gas FIP? We note that if we create such
exemptions, it would minimize the possibility of creating conflicting
provisions, although we could potentially require that the more
stringent provisions would apply where a conflict occurs. On the other
hand, it could result in emission units at different sources being
subject to requirements that are not of equal stringency. We request
comment on this issue.
Finally, based on our experience with the Fort Berthold FIP, there
may be numerous sources that would be major based on their PTE, but
whose actual emissions are below the major source threshold. We are
requesting comment on whether a FIP should address these sources, and
how that might be accomplished.
E. Which pollutants would we regulate?
Sources in the oil and natural gas production segment emit a number
of different air pollutants. Section IV. provides a general overview of
the exploratory and production processes and their associated
emissions. To function as an appropriate substitute for the minor NSR
permitting program, an oil and natural gas FIP or general permit would
need to regulate emissions of all ``regulated NSR pollutants'' from
minor sources that construct, or major or minor sources that undertake
a minor modification. This would mean that an oil and natural gas FIP
or general permit could regulate all criteria pollutants and all PSD
pollutants emitted or potentially emitted by activities at minor
sources that would construct, or minor or major sources that would
undertake a minor modification. We are not aware of an advantage to
regulating only a portion of the regulated NSR pollutants through a FIP
or general permit and allowing other pollutants to remain subject to
site-specific permitting through the Indian Country Minor NSR rule. If
we do not regulate all pollutants under a FIP or general permit, then
we would continue to require sources to obtain minor NSR permits for
the pollutants not covered by the FIP or general permit through the
minor NSR permitting program.
Based on existing air quality information, including area
designations, which indicates that attainment of the 2008 8-hour ozone
NAAQS may pose the biggest concern from the expansion of the oil and
natural gas production segment, the pollutants of interest include
NOX and VOC. Because our objective in regulating existing
emissions units would be to address emerging ozone concerns and provide
for economic growth in Indian country in a manner that avoids such
degradation, we might consider only regulating emissions related to
ozone. We request comment on which criteria pollutants and/or
precursors should be regulated for oil and natural gas sources in
Indian country.
[[Page 32519]]
F. How would we determine the appropriate control requirements for new
and modified sources and existing sources?
The EPA seeks input on the types of emission control requirements
that would be appropriate for new and modified minor sources and minor
modifications at major sources. The EPA also seeks input on the types
of emission control requirements that would be appropriate for existing
sources, if we were to propose a FIP for new sources as well as for
existing sources.
The Indian Country Minor NSR rule requires a reviewing authority to
undertake a case-specific control technology review to determine the
appropriate level of emissions control for a new or modified emission
unit. As part of that control technology review, the reviewing
authority considers local air quality needs, typical control technology
used by similar sources in surrounding areas, anticipated economic
growth in the area, and cost-effective control alternatives (76 FR
38760, July 1, 2011). If we establish a uniform set of control
technology requirements for new, modified and existing sources under an
oil and natural gas production FIP, then we envision undertaking a
similar, but not identical, control technology review to establish the
requirements. Specifically, we envision that we would develop a list of
potential control technology options by reviewing requirements that are
currently applicable or under consideration by state and local air
pollution agencies. We also might consider requirements in the FIP that
applies to the Fort Berthold Indian Reservation (78 FR 17836, March 22,
2013), performance standards (including work practice standards) in
NSPS regulations, and recommendations in control techniques guidelines
(CTG), alternative control techniques (ACT), and in the EPA's Natural
Gas Star program. We may also consult other sources of outside
information. We request comment on specific relevant sources of
information.
In evaluating the relative merits of various potential control
technology options, we would follow a process that considers factors
used in the EPA's BACT approach of weighing energy, environmental, and
economic impacts, and other costs; however, we would not be bound to
selecting controls based on the maximum achievable level of control,
but instead could consider the degree of enhanced protection
appropriate or necessary on a nationwide basis. If we tailor
requirements to the needs of individual air basins or air quality
control regions, then we may follow a similar approach for identifying
control technology options in a FIP or general permit, or look to
mirror requirements applying in surrounding states.
We request comment on these approaches for establishing emissions
control requirements in a FIP or general permit. We specifically seek
comment on whether any particular state regulation could serve as a
good model for constructing requirements that would apply in a specific
area, or on a nationwide basis.
G. Should we require sources to install and collect data from ambient
air quality monitors?
As discussed in Section IV.B., our understanding of the oil and
natural gas sector's impact on ambient air quality in Indian country is
incomplete at this time given the absence of ambient air quality
monitoring sites in many areas of Indian country. At the same time,
with the prospect of continued significant growth in emissions from the
oil and natural gas sector, it may be necessary or appropriate to
impose emissions control requirements on existing emissions units. More
detailed information on the air quality in a region would help us
better understand whether emission reductions from existing sources are
necessary or appropriate to accommodate emissions growth while still
protecting public health.
We seek comment on whether and how we might use our CAA section 114
or other CAA authority to require oil and natural gas sources in Indian
country to install and operate ambient air monitors. For example,
should we require emission controls on existing oil and natural gas
sources in all areas of Indian country unless ambient air quality
monitors demonstrate that there is not a need for such requirements? In
lieu of including specific ambient monitoring requirements, we seek
comment on whether and how we might encourage sources to voluntarily
install and maintain air quality monitors that meet Federal reference
monitoring (FRM) requirements.
H. Next Generation Compliance
Enforcing regulatory requirements imposed on the oil and natural
gas production segment in Indian country poses unique challenges for
regulators. In states, sources face compliance oversight by both
Federal and state regulators. While tribes and the Federal government
are actively building tribal capacity to accept delegation of
implementation programs, this capacity is still developing in many
areas. Consequently, EPA Regional Office personnel may provide the sole
resource for compliance oversight, and they will likely face resource
challenges with regard to enforcement.
The nature of the oil and natural gas production segment in Indian
country compounds this potential problem. The industry includes
numerous, geographically dispersed pollutant-emitting activities.
Unlike a power plant, for example, that emits large amounts of criteria
pollutants from a few, specific, well-defined emission points (i.e.,
smoke stacks), the oil and natural gas production segment may produce
emissions from multiple, diverse, geographically-dispersed sources in
relatively lower amounts. Collectively, however, these smaller sources
can have adverse air impacts. But, the sheer numbers of well pads and
the nature of the pollutant-emitting activities pose challenges for
developing a strategically effective enforcement program for Indian
country. We may not be able to rely on the traditional single-facility
inspection and enforcement approach to ensure widespread compliance.
Accordingly, we are requesting comment on ways the EPA can use Next
Generation Compliance methods to promote compliance with a FIP, general
permit, or other approach such as a permit by rule.
Next Generation Compliance is a multi-facet concept that
encompasses (1) Using advances in emissions monitoring and information
technology to readily detect violations and allow rapid corrective
action by regulated entities or regulators; (2) using electronic
reporting (e-reporting) systems to provide more timely and transparent
emissions information to regulators and the public; and (3) building
compliance management and incentive programs within regulations to
promote compliance. Through Next Generation Compliance, the EPA can
leverage motivational factors, market forces, technologies, and public
accountability to drive higher compliance rates.
We are interested in gaining feedback on existing or emerging
monitoring and information technologies that can be used by the oil and
natural gas production segment to promote compliance. For example,
would infrared monitoring systems provide a cost effective method for
either detecting fugitive emissions at remote well pads, or hidden
mechanical or electrical problems that could lead to process-upset
emissions events? Are there any monitoring systems used by
[[Page 32520]]
the industry to comply with Occupational Safety and Health Act
regulations and other safety laws (e.g. photoionization detectors) that
might be used in tandem with protocols under a FIP or general permit to
ensure compliance? Are there any process-based monitoring systems
already in use by the industry that could serve as an effective
predictive or surrogate monitoring system in lieu of monitoring
emissions directly? Are any immediate feedback technologies available
or emerging that would provide the operator with real time measures of,
or information on, their compliance status?
With regard to advances in reporting and transparency, we would
intend to make e-reporting the default method of reporting information
under a future permitting program for oil and natural gas production
sources in Indian country. E-reporting is a standardized, internet-
based, electronic reporting system. E-reporting reduces the cost of
complying with reporting requirements compared to paper reporting
systems. Also, with e-reporting, the EPA and public gain more timely
access to compliance information and industry perceives a greater
incentive to comply, because data are more readily available and
transparent to the public. Although we would intend to rely on e-
reporting as the default reporting method in a future permitting
program for the oil and natural gas production segment in Indian
country, we request comment on whether the segment faces any unique
challenges that we should consider relative to the type of information
collected, the frequency of collection, or the database system used to
store information.
We also request comment on the feasibility of using third-party
compliance verification as a means for demonstrating compliance. Third-
party compliance verification relies on a party external to a
facility,\48\ such as a private auditor or inspector, to verify and
report a facility's compliance status. Third-party compliance
verification can enhance accountability, improve compliance, and
produce more and better compliance data.
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\48\ ``External to the facility'' means that the party is
neither the regulated entity nor a customer, supplier or purchaser
of the facility's goods or services.
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A successful third-party compliance system relies on the
availability of competent and independent third parties. This means
that the person conducting the compliance verification possesses the
technical expertise and professional judgement to properly verify
compliance. For purposes of an oil and natural gas FIP or general
permit, what minimum level of education, experience, or training is
appropriate? Should we require third parties to meet certain
accreditation standards, and/or meet a minimum set of requirements to
demonstrate independence? For example, the Food and Drug Administration
(FDA) specifies requirements for independence and lack of a financial
conflict of interest for persons carrying out section 510(k) of the FDA
Modernization Act of 1997.\49\ Other requirements we could consider
might be prohibiting the auditor from consulting with the clients on
corrective actions to ensure financial independence; assigning
verifiers to facilities randomly rather than allowing a company to
select their verifier; limiting the number of occasions a company can
rely on the same verifier; and barring the company from hiring a
verifier for an established waiting period.
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\49\ See U.S. Dept. of Health and Human Services, Food and Drug
Admin., ``Implementation of Third Party Programs under the FDA
Modernization Act of 1997: Final Guidance for Staff, Industry and
Third Parties,'' Feb. 2, 2001, available at http://www.fda.gov/MedicalDevices/DeviceRegulationandGuidance/GuidanceDocuments/ucm094450.htm.
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One criticism that people have regarding third-party verification
programs is that outside parties lack the specialized knowledge and
understanding of standard business practices for a particular
organization to most effectively audit company records. One
recommendation that flows from this complaint is that companies that
use an internal audit system in conjunction with an ISO 14001
environmental management system should be permitted to rely on their
internal, but sufficiently independent, auditing departments. Because
of familiarity with standard business practices, internal auditors may
have a higher level of understanding of the business' activities and,
therefore, be able to conduct more thorough audits then external
auditors. We request comment on the use of independent internal audit
systems for compliance verification. Should the EPA allow such an
approach for compliance with a future permitting program for oil and
natural gas sources in Indian country? If so, then what measures should
the EPA impose to ensure an absence of a conflict of interest? Should a
company be required to rely on an external third party for some
demonstration period, after which a company could transition to an
internal auditing department?
We request comment on all aspects of using an independent
compliance verification system to enhance and promote compliance. We
specifically request comment on the issues we raise above, and on
whether such a system should be mandatory for all sources regulated
under a potential FIP, general permit, or other approach, or only for
those who choose a flexible, alternative method of compliance.
In addition to the use of an independent compliance verification
system, we request comment on two compliance incentive programs: (1) An
automatic, pre-set penalty system, and (2) use of modified monitoring,
recordkeeping and/or reporting requirements. With an automatic, pre-set
penalty system, the regulation could specify a set monetary penalty for
certain non-compliance events. This penalty would be payable upon
disclosure of an excess emissions event without notice or issuance of a
demand for payment. The sum of the penalty could vary based on whether
non-compliance was self-disclosed, disclosed by a third-party auditor,
or discovered by EPA enforcement. Importantly, we would design an
automatic penalty provision to encourage compliance by making the path
to compliance easier than non-compliance. For example, the EPA's Acid
Rain Program assesses an excess emissions penalty set at $2,000/ton
(adjusted annually for inflation). This penalty exceeds the cost of
complying with the program and serves as an effective deterrent against
non-compliance.\50\
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\50\ For example, in 2004, four sources were assessed a penalty
of approximately $1.4 million for excess SO2 emissions.
These sources would have spent only $139,500 to comply with the
program. See J. Schakenbach, R. Vollaro and R. Forte, U.S. EPA,
Office of Atmospheric Programs, ``Fundamentals of Successful
Monitoring, Reporting, and Verification under a Cap-and-Trade
Program,'' Journal of the Air & Waste Management Assoc., vol 56, p
1576, Nov. 2006, available at http://www.epa.gov/airmarkets/cap-trade/docs/fundamentals.pdf.
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A modified monitoring, recordkeeping and reporting program would
reward facilities for demonstrating a continued commitment to
compliance by adjusting the frequency or type of monitoring,
recordkeeping and reporting that is required based on the particular
facility's compliance record. It may also incorporate substitute
emission data requirements that become increasingly more conservative
when the facility experiences repeated data collection failures. This
provides an incentive for operators to properly maintain and operate
monitoring systems.
In sum, we request comment on any manner in which the Agency can
use
[[Page 32521]]
principles of Next Generation Compliance to promote higher rates of
compliance with requirements we may include in a FIP, general permit,
or other permitting approach for oil and natural gas production sources
located in Indian country. Our objective is to promote high rates of
compliance through cost-effective, incentive-based approaches that
capitalize on existing systems used by the industry, and that ensure
the availability and transparency of compliance information to the
public and the EPA.
VIII. Statutory and Executive Order Reviews
Under Executive Order 12866 Regulatory Planning and Review (58 FR
51735, October 4, 1993) and Executive Order 13563 Improving Regulation
and Regulatory Review (76 FR 3821, January 21, 2011), this is not a
``significant regulatory action.'' Because this action does not propose
or impose any requirements, the various statutes and Executive Orders
that normally apply to rulemaking do not apply. Should the EPA
subsequently determine to pursue a rulemaking, the EPA will address the
statutes and Executive Orders as applicable to that rulemaking.
Because this document does not impose or propose any requirements,
and instead seeks comments and suggestions for the Agency to consider
in possibly developing a subsequent proposed rule, the various other
review requirements that apply when an agency imposes requirements do
not apply to this action.
The EPA seeks any comments or information that would help the
Agency ultimately to assess the potential impact of a rule on small
entities pursuant to the Regulatory Flexibility Act (RFA) (5 U.S.C. 601
et seq.); to consider voluntary consensus standards pursuant to section
12(d) of the National Technology Transfer and Advancement Act of 1995
(NTTAA) (15 U.S.C. 272 note); to consider environmental health or
safety effects on children pursuant to Executive Order 13045, entitled
``Protection of Children from Environmental Health Risks and Safety
Risks'' (62 FR 19885, April 23, 1997); or to consider human health or
environmental effects on minority or low-income populations pursuant to
Executive Order 12898, entitled ``Federal Actions to Address
Environmental Justice in Minority Populations and Low-Income
Populations'' (59 FR 7629, February 16, 1994).
The Agency will consider such comments during the development of
any subsequent proposed rule.
List of Subjects in 40 CFR Part 49
Environmental protection, Administrative practices and procedures,
Air pollution control, Indians, Indians-law, Indians-tribal government,
Intergovernmental relations, Reporting and recordkeeping requirements.
Dated: May 22, 2014.
Gina McCarthy,
Administrator.
[FR Doc. 2014-12951 Filed 6-4-14; 8:45 am]
BILLING CODE 6560-50-P