Document ID: EPA-R08-OAR-2012-0479-0002
Agency: epa
Document Type: Rule
Title: Approvals and Promulgations of Federal Implementation Plans for Oil and Natural Gas Well Production Facilities: Fort Berthold Indian Reservation, ND
Posted Date: 2012-08-15T04:00Z

[Federal Register Volume 77, Number 158 (Wednesday, August 15, 2012)]
[Rules and Regulations]
[Pages 48878-48898]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-19698]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 49

[EPA-R08-OAR-2012-0479; FRL-9710-4]

Approval and Promulgation of Federal Implementation Plan for Oil 
and Natural Gas Well Production Facilities; Fort Berthold Indian 
Reservation (Mandan, Hidatsa, and Arikara Nations), ND

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: EPA is taking final action to promulgate a Reservation-
specific Federal Implementation Plan in order to regulate emissions 
from oil and natural gas production facilities located on the Fort 
Berthold Indian Reservation located in North Dakota. The Federal 
Implementation Plan includes basic air quality regulations for the 
protection of communities in and adjacent to the Fort Berthold Indian 
Reservation. The Federal Implementation Plan requires owners and 
operators of oil and natural gas production facilities to reduce 
emissions of volatile organic compounds emanating from well 
completions, recompletions, and production and storage operations. This 
Federal Implementation Plan will be implemented by EPA, or a delegated 
Tribal Authority, until replaced by a Tribal Implementation Plan. EPA 
is proposing a Reservation-specific Federal Implementation Plan 
concurrently with this final rule.

DATES: This rule is effective in the CFR on August 15, 2012. This rule 
is effective with actual notice by EPA to the owners and operators for 
purposes of enforcement beginning at 5 p.m. (eastern daylight time) on 
August 3, 2012.
    Public Hearing: EPA will hold a public hearing on the following 
date: September 12, 2012. The hearing will start at 1 p.m. local time 
and continue until 4 p.m. or until everyone has had a chance to speak. 
Additionally, an evening session will be held from 6 p.m. until 8 p.m. 
The hearing will be held at the 4 Bears Casino & Lodge, 202 Frontage 
Rd, New Town, ND 58763, (701) 627-4018.

ADDRESSES: 
    Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some 
information is not publicly available, e.g., CBI or other information 
whose disclosure is restricted by statute. Certain other material, such 
as copyrighted material, will be publicly available only in hard copy. 
Publicly-available docket materials are available either electronically 
in http://www.regulations.gov or in hard copy at the following 
locations: Air Program, U.S. Environmental Protection Agency (EPA), 
Region 8, Mailcode 8P-AR, 1595 Wynkoop, Denver, Colorado 80202-1129; 
and Environmental Division, Three Affiliated Tribes, 204 West Main, New 
Town, North Dakota 58763-9404. EPA requests that if at all possible, 
you contact the individuals listed in the FOR FURTHER INFORMATION 
CONTACT section to view the hard copy of the docket. You may view the 
hard copy of the docket Monday through Friday, 8 a.m. to 4 p.m., 
excluding Federal holidays.

FOR FURTHER INFORMATION CONTACT: Deirdre Rothery, U. S. Environmental 
Protection Agency, Region 8, Air Program, Mail Code 8P-AR, 1595 Wynkoop 
Street, Denver, Colorado 80202-1129, (303) 312-6431, 
rothery.deirdre@epa.gov.

SUPPLEMENTARY INFORMATION: Throughout this document, ``we,'' ``us'' and 
``our'' refer to the EPA.

Definitions

    For the purpose of this document, we are giving meaning to 
certain words or initials as follows:

(i) The initials APA mean or refer to the Administrative Procedure 
Act.
(ii) The words or initials Act or CAA mean or refer to the Clean Air 
Act, unless the context indicates otherwise.
(iii) The initials BTU mean or refer to British Thermal Unit.
(iv) The initials CAFOs mean or refer to Consent Agreement Final 
Orders.
(v) The initials CDPHE mean or refer to Colorado Department of 
Public Health and Environment Air Pollution Control Division.
(vi) The initials CO mean or refer to carbon monoxide.
(vii) The words EPA, we, us or our mean or refer to the United 
States Environmental Protection Agency.
(viii) The words Reservation or the initials FBIR mean or refer to 
the Fort Berthold Indian Reservation.
(ix) The initials FIP mean or refer to Federal Implementation Plan.
(x) The initials GOR mean or refer to gas-to-oil ratio.
(xi) The initials LACT mean or refer to lease automatic custody 
transfer.
(xii) The initials MDEQ mean or refer to Montana Department of 
Environmental Quality.
(xiii) The initials NAAQS mean or refer to the National Ambient Air 
Quality Standards.
(xiv) The initials NAICS mean or refer to the North American 
Industry Classification System.
(xv) The initials NDDoH mean or refer to the North Dakota Department 
of Health.
(xvi) The initials NDIC mean or refer to the North Dakota Industrial 
Commission.
(xvii) The initials NESHAP mean or refer to National Emission 
Standards for Hazardous Air Pollutants.
(xviii) The initials NMED mean or refer to New Mexico Environment 
Department Air Quality Bureau.
(xix) The initials NOX mean or refer to nitrogen oxides.
(xx) The initials NO2 mean or refer to nitrogen dioxide.
(xxi) The initials NSPS mean or refer to New Source Performance 
Standards.
(xxii) The initials NSR mean or refer to new source review.
(xxiii) The initials ODEQ mean or refer to Oklahoma Department of 
Environmental Quality Air Quality Division.
(xxiv) The initials PM mean or refer to particulate matter.
(xxv) The initials PSD mean or refer to prevention of significant 
deterioration.
(xxvi) The initials PTE mean or refer to potential to emit.
(xxvii) The initials RCT mean or refer to Railroad Commission of 
Texas, Oil and Gas Division.
(xxviii) The initials SCADA mean or refer to Supervisory Control and 
Data Acquisition.
(xxix) The initials SIP mean or refer to State Implementation Plan.
(xxx) The initials SO2 mean or refer to sulfur dioxide.

[[Page 48879]]

(xxxi) The initials TAR mean or refer to Tribal Authority Rule.
(xxxii) The initials TAS mean or refer to treatment as state.
(xxxiii) The initials TIP mean or refer to Tribal Implementation 
Plan.
(xxxiv) The initials UDEQ mean or refer to Utah Department of 
Environmental Quality.
(xxxv) The initials VOC mean or refer to volatile organic 
compound(s).
(xxxvi) The initials VRU mean or refer to vapor recovery unit.
(xxxvii) The initials WDEQ mean or refer to Wyoming Department of 
Environmental Quality Air Quality Division.

Table of Contents

I. Justification for This Final Rule
    A. Overview
    B. Rationale for the Final Rule
II. Proposed Rulemaking
III. Background
    A. Today's Action
    B. Purpose of the Rule
    C. Development of the Rule
    D. Area and Facilities Covered by the FIP
    E. Effect on Permitting of Facilities
    F. Registration Requirements
    G. Applicability to New and Existing and Modified Facilities
    H. Attainment Status
    I. Benefits and Costs
IV. The Fort Berthold Indian Reservation
V. EPA's Authority To Promulgate a FIP
VI. Summary of FIP Provisions
    A. Applicability
    B. Compliance Schedule
    C. Provisions for Delegation of Administration to the Tribes
    D. General Provisions
    E. Construction and Operational Control Measures
    F. Control Equipment Requirements
    G. Monitoring Requirements
    H. Recordkeeping Requirements
    I. Reporting Requirements
VII. Statutory and Executive Order

I. Justification for This Final Rule

A. Overview

    In today's action, we are promulgating a Reservation-specific 
Federal Implementation Plan (FIP or rule) to establish enforceable 
control requirements for reducing volatile organic compound (VOC) 
emissions from oil and natural gas production activities on the Fort 
Berthold Indian Reservation (FBIR) in North Dakota. Specifically, we 
are issuing this rule to require owners and operators of oil and 
natural gas production facilities producing from the Bakken Pool to 
reduce emissions of VOCs emanating from well completions, 
recompletions, and production and storage operations. As explained in 
more detail in Section III, promulgating these Federal regulations 
addresses an important initial step to fill a regulatory gap with 
regard to controlling VOC emissions from oil and natural gas operations 
on the FBIR. There is no other Federal rule, including the recently 
finalized New Source Performance Standard (NSPS) and National Emission 
Standards for Hazardous Air Pollutants (NESHAP) for the Oil and Gas 
Sector (NSPS OOOO and NESHAP HH), that fills this gap for the 
particular geologic formations that exist on the FBIR. Therefore, this 
rule is necessary to level the playing field, and provide the public on 
the FBIR the same air quality protections as the public outside the 
FBIR. In addition, owners and operators of oil and natural gas 
operations on the FBIR are provided the same benefits that owners and 
operators of oil and natural gas operations off the Reservation are 
provided by the North Dakota Department of Health (NDDoH) regulations 
and North Dakota Industrial Commission (NDIC) regulations in terms of 
effectively limiting potential to emit (PTE).\1\
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    \1\ Depending on the emissions characteristics of a particular 
well, compliance with the requirements of the FIP may or may not 
limit the well's PTE to below the major source thresholds such that 
the well is not subject to major source prevention of significant 
(PSD) permitting and/or to national emission standards for hazardous 
air pollutants (NESHAP) requirements.
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B. Rationale for the Final Rule

    EPA is issuing this action as a final rule. As explained in Section 
III., the final rule requires owners and operators of oil and natural 
gas production facilities on the FBIR to reduce emissions of VOC for 
specific types of equipment. This final rule will take effect promptly. 
It will be effective in the CFR on August 15, 2012. It will also be 
effective, with actual notice by EPA to the owners and operators, for 
purposes of enforcement beginning at 5 p.m. (eastern daylight time) on 
August 3, 2012. This final rule is also time-limited. It will be 
effective only until the date that EPA promulgates a final rule based 
on its proposal for a Reservation-specific FIP to regulate emissions 
from oil and natural gas production facilities located on the FBIR and 
that final rule takes effect. EPA is proposing a Reservation-specific 
FIP concurrently with this final rule. As explained in detail below, 
EPA finds that compelling circumstances warrant the promulgation of 
this final rule.
    A final rule is effective with actual notice upon signature by the 
EPA without an opportunity for public comment. Under APA section 553, a 
Federal agency generally must provide for public notice and comment 
prior to finalizing an agency rule. However, this obligation is 
excused, under APA section 553(b)(3)(B), ``when the agency for good 
cause finds (and incorporates the finding and a brief statement of 
reasons therefore in the rules issued) that notice and public procedure 
thereon are impracticable, unnecessary, or contrary to the public 
interest.'' While the good cause exception is to be narrowly construed, 
Utility Solid Waste Activities Group v. Environmental Protection 
Agency, 236 F.3d 749, 754 (D.C. Cir. 2001), it is also ``an important 
safety valve to be used where delay would do real harm.'' U.S. Steel 
Corp. v. U.S. Environmental Protection Agency, 595 F.2d 207, 214 (5th 
Cir. 1979). Notice and comment are impracticable where ``an agency 
finds that due and timely execution of its functions would be impeded 
by the notice otherwise required.'' Utility Solid Waste Activities 
Group, 236 F.3d at 754. Notice and comment are contrary to the public 
interest where ``the interest of the public would be defeated by any 
requirement of advance notice.'' Id. at 755.
    A brief explanation of the circumstances is helpful to understand 
why Notice and comment here would be both contrary to the public 
interest and impracticable and therefore why there is good cause to 
implement this final rule while the agency conducts a notice and 
comment rulemaking for the permanent rule. The need to address VOC 
emissions from coproduced natural gas from oil and natural gas 
production sources on the FBIR was first brought to EPA's attention 
approximately 12 months ago, following publication of the Review of New 
Sources and Modifications in Indian Country or Federal Tribal NSR Rule, 
promulgated on July 1, 2011, at 40 CFR 49.151 (see 76 FR 38748). At 
that time, a significant number of entities engaged in oil and natural 
gas production operations on the FBIR informed EPA that the emissions 
of regulated air pollutants, including volatile organic compounds 
(VOCs), from oil and natural gas production facilities were 
significantly larger than they had previously understood. These 
emissions created a public health and safety hazard and were 
sufficiently large that hundreds of individual facilities would 
potentially be required to obtain major source PSD permits unless they 
were able to obtain legal and practicably enforceable emission limits 
on the facilities' potential-to-emit.
    In August 2011, EPA and the operators entered into consent 
agreement final orders (CAFOs), which established control requirements 
that restricted emissions from the oil and natural gas production 
facilities subject to those agreements to below major source thresholds 
and allowed the

[[Page 48880]]

operators to continue to operate pending issuance of appropriate 
permits.
    In late August 2011, the EPA Region 8 initiated a process to 
develop, propose and issue permits to the hundreds of sources on the 
FBIR (both existing and proposed new wells) and to develop a FIP. At 
that time, EPA lacked detailed information to develop permits (e.g., 
information about the facilities, emissions, and possible emission 
controls) and therefore, hosted numerous meetings from August through 
November 2011 to collect the necessary information and develop complete 
permit applications and draft permit language.\2\ The EPA drafted and 
proposed the first batch of permits in March 2012, \3\ and explained in 
our April 10, 2012 letter to Chairman Hall that ``[t]he comment period 
for these permits will end on April 23, 2012, at which time we will 
consider comments and finalize these permits,'' noting that ``these 
completed permits will form the basis for the FIP.'' While we had 
developed an example permit to provide predictability and a framework 
for permitting, it was clear that each permit would need to be 
developed on a case-by-case basis using information submitted in each 
application.
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    \2\ Resolving the challenges on the FBIR has been a top priority 
for EPA. The Agency has dedicated enormous resources to resolve 
these challenges at the Regional and National offices for nearly a 
year and continues to do so. EPA's efforts have included the 
following activities.
    In late August 2011, the EPA Region 8 air permit and enforcement 
programs hosted a Fort Berthold Oil Production Minor NSR Permitting 
Process Meeting with the oil producers. Representatives from the MHA 
Nation were invited and attended in person and by phone. Discussions 
included the anticipated permitting timeline for permit applications 
submitted by the oil producers. Between August 23 and September 1, 
2011, a draft model synthetic minor permit was sent by EPA to the 
meeting attendees and the Tribes in preparation for the next meeting 
on September 1, 2011. Then, on September 1, 2011, Region 8 hosted a 
permitting workshop. Representatives from the various oil producers 
and the MHA Nation were invited and attended. Representatives of the 
North Dakota Dept. of Health also participated by phone. The minor 
NSR permitting process was discussed, as well as questions that the 
companies submitted ahead of time. The group began discussions on 
the draft model permit and set up a workshop specifically to delve 
into the specific permit conditions for the following week. On 
September 7 and 8, 2011, EPA hosted a two-day follow-up permitting 
workshop. All previous meeting attendees were invited, including the 
MHA Nation. Participants included the oil producers and their 
consultants. North Dakota Department of Health representatives were 
also on the phone. At this meeting the group went through the draft 
model permit and discussed the proposed conditions and appropriate 
edits. Also discussed was what would constitute a complete 
application (administrative and technical) and the various methods 
of PTE calculation proposed by the companies in attendance. The EPA 
Region 8 hosted an additional meeting on November 30, 2011 to 
discuss the revised example permit, and representatives from the 
various oil producers and the MHA Nation were invited and attended.
    \3\ The draft permits that underwent a public review and comment 
period are available online at: http://www.epa.gov/region8/air/permitting/pubcomment.html.
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    We initially planned to issue all of the necessary permits before 
August 26, 2012, the earliest expiration date of the CAFOs. However, in 
May 2012, the true extent of the significant workload associated with 
developing and finalizing permits for more than 600 existing and new 
oil and natural gas production facilities became apparent. It became 
clear that, due to the extraordinary number of permits that needed to 
be issued, the need to tailor each of those permits to comport with the 
information in the permit application and the short timeframe remaining 
to complete those tasks, it would not be possible to issue all, or even 
a significant portion of, the final permits by August 26, 2012. 
Moreover, given the rapid pace of oil and gas development on the FBIR, 
there are likely numerous additional sources that will each need a 
permit in addition to sources EPA is aware of at this time. We 
therefore determined that the only way to ameliorate the situation in a 
timely manner was through this rulemaking action. We contemplated 
developing the FIP in addition to issuing the individual permits, but 
determined that promulgating the FIP should be our top priority once we 
realized that we could not issue all of the necessary permits in a 
timely manner.
    Key safety provisions of the final rule require either collection 
and high efficiency flaring (combustion) of coproduced natural gas or 
that the well(s) be connected to a natural gas gathering line so that 
coproduced natural gas can be sold or used for another beneficial 
purpose. Given the accelerated development in this area and the nature 
of the oil and gas extracted, these requirements are necessary for both 
safety and protection of public health from exposure to air pollution 
and will avoid fire hazards and protect the public from hazardous 
conditions. Specifically, the requirements further a number of 
important goals in that regard. First, as discussed in Section III.C., 
VOC emissions from the natural gas that is co-produced with oil 
extracted from the formations are generally greater than such emissions 
from activities in other oil bearing formations, due to the 
characteristics of the produced oil. The FIP requirements for owners 
and operators of the oil and natural gas production facilities to 
reduce emissions of VOCs emanating from well completions, recompletions 
and production and storage operations will significantly reduce VOC 
emissions thereby ensuring that public health and the environment are 
protected. Second, the rule will result in immediate reductions in fire 
risks and improvements in air quality as a result of control of 
emissions from both new and existing oil and gas operations. 
Accordingly, as a result of the unique characteristics of the 
formations at issue, immediate application of the FIP requirements to 
both new and existing oil and natural gas operations is necessary to 
ensure that public health and the environment, continue to be protected 
once consent agreement final orders (CAFOs) with EPA expire.
    The requirements of the FIP also serve to minimize regulatory 
burden in a number of ways. This rule ensures that ongoing oil and gas 
operations (including modifications), and new operations, can occur 
uninterrupted in a manner consistent with the Clean Air Act (CAA), thus 
protecting the economic interest of both the companies and Tribes 
involved and the local communities. The oil and natural gas production 
companies operating on the FBIR entered into CAFOs with EPA which 
allowed them to continue existing operations and begin new ones without 
first complying with major source prevention of significant 
deterioration (PSD) new source review (NSR) requirements if applicable, 
which can be a very lengthy and resource-intensive process. These CAFOs 
are further discussed in Section III.G. The CAFOs, which contain 
emissions control and other requirements that are consistent with those 
in the rule adopted today, have been in place since August 2011 and 
will expire beginning on August 26, 2012,\4\ a date which is rapidly 
approaching. In the absence of this rule, hundreds of new and existing 
oil and natural gas production sources on the FBIR that are subject to 
these CAFOs would be unable to continue to operate, construct or modify 
in compliance with CAA requirements without first obtaining a permit 
from EPA because they will have no legally and practicably enforceable 
requirements in place controlling VOC emissions, thus significantly 
disrupting ongoing economic activities and the benefits those 
activities bring to the communities of the Reservation.
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    \4\ The FBIR CAFOs are included in the docket for this rule.
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    As a result, without this final rule there will be a mixture of 
circumstances that will increase potential threats to human health and 
the environment while simultaneously impeding oil and gas development. 
This is because of the

[[Page 48881]]

mix of current CAA obligations that currently apply to these wells. 
While many sources would first need to obtain a PSD permit to construct 
or would need to resolve ongoing violations to continue to operate, 
other sources could operate without obtaining a permit. Accordingly, 
sources that need to resolve permitting obligations would be delayed in 
construction or operation (impeding development) while those without 
permitting obligations would operate uncontrolled as the final rule 
requirements would not be in place.
    In summary, this rule serves the necessary function of ensuring 
that a regulation is in place to control emissions of VOCs by these 
sources. These provisions contain legally and practicably enforceable 
requirements to use control measures to reduce VOC emissions such that 
those reductions can then be considered in calculating a source's PTE. 
In most cases, consideration of these emission reductions in 
calculating a source's PTE VOCs will result in a PTE that is below the 
regulatory threshold so that the source will not face a long delay in 
its ability to continue to operate, construct or modify. The public 
interest would certainly be hindered if EPA did not act now to ensure 
that these important public health protections are in place and that 
economic progress is not impeded by a lack of regulations controlling 
VOC emissions.
    Finally, this rule is important in that while not identical to, the 
rule is consistent with regulations approved into North Dakota's SIP 
\5\ under the authority of the NDDoH and regulations under the 
authority of the NDIC,\6\ which were established for similar purposes. 
Accordingly, this rule ensures that consistent requirements apply to 
activities both inside of and within the FBIR.
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    \5\ North Dakota Century Code (NDCC) (Chapter 23-25 Air 
Pollution Control); Air Pollution Control Rules (Article 33-15) 
Chapter 33-15-07 Control of Organic Compound Emissions, and Chapter 
33-15-20-04 Control of Emissions from Oil and Gas Well Production 
Facilities. North Dakota Legislative Branch. Available online at: 
http://www.legis.nd.gov/information/acdata/html/33-15.html. Accessed 
May 29, 2012. Within EPA approved SIP.
    \6\ NDCC (Chapter 38-08 Control of Oil and Gas Resources); 
Article 38-08-06.4. Flaring of Gas Restricted--Imposition of Tax--
Payment of Royalties--Industrial Commission Authority; and Article 
43-02-03-28 Safety Regulation. Available online at: https://www.dmr.nd.gov/oilgas/rules/rulebook.pdf. Accessed July 5, 2012. 
State only rule.
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    The good cause exception also applies here because of the 
impracticability of notice and comment. EPA initially did not recognize 
the sheer magnitude of the volume of permit applications that it would 
need to process in a short time period to avoid economic disruption on 
the Reservation. Now that it fully comprehends the enormity of the 
task, EPA has determined that it would be unable to timely process more 
than 600 permit applications, specified to be submitted as part of the 
CAFOs between EPA and the oil and natural gas owners and operators by 
August 2012. Because of our inability to process these permits, and 
because of lateness at which we became fully aware of the full scope of 
the burden, EPA thus has had insufficient time to seek public comment 
before acting on the rule promulgated today.
    While we have determined that notice and comment are both contrary 
to the public interest and impracticable, we note that the public has 
had several opportunities to learn about, and even comment on, the 
substantive requirements contained in this interim rule. The substance 
of many provisions in the final rule are similar to the requirements 
contained in the six permits for individual oil and gas production 
facilities on the FBIR that EPA proposed earlier this year. We received 
comments from the public and the sources on those proposed permits and 
we have taken those comments into consideration in developing the FIP 
requirements. The substantive requirements of the FIP are also similar 
to the conditions in the CAFOs under which the oil and natural gas 
production sources have been operating for nearly a year, and the 
public had notice of the CAFOs, which were posted on EPA's Internet 
site for public review.\7\ Furthermore, the public has an additional, 
full opportunity to comment on the permanent rule that EPA is 
concurrently proposing today, which mirrors, and will replace this 
interim rule. By issuing this rule as a final rule, paired with a 
comment period on the proposal for more permanent action, EPA is 
providing as much opportunity for notice and comment as possible on the 
issues presented by this rule. EPA will expeditiously and fully, 
consider any comments received on the proposed rule, and once we have 
completed our deliberative process, will make any necessary revisions 
in taking final action on the proposed rule.
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    \7\ EPA Administrative Enforcement Dockets, available at: http://yosemite.epa.gov/oa/rhc/epaadmin.nsf.
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    For the reasons discussed above, EPA finds both that there is good 
cause to forego notice and comment for this interim rule, and that 
there is good cause for this rule to take immediate effect and to take 
effect as described above, for those sources that receive actual notice 
for purposes of enforcement. Since this is not a major rule under the 
Congressional Review Act (CRA), the 60-day delay in effective date 
required for major rules under the CRA does not apply.

II. Proposed Rulemaking

    We are also simultaneously publishing a parallel proposed 
rulemaking which seeks comment on information found within this final 
rule. Note that Docket Number EPA-R08-OAR-2012-0479 is being used for 
both the final rule and the parallel proposed rule.

III. Background

A. Today's Action

    In today's action, we are promulgating a Reservation-specific FIP 
to establish enforceable control requirements for reducing VOC 
emissions from oil and natural gas production activities on the FBIR in 
North Dakota. Specifically, we are issuing this rule to require owners 
and operators of oil and natural gas production facilities producing 
from the Bakken Pool \8\ to reduce emissions of VOCs emanating from 
well completions, recompletions, and production and storage operations. 
Oil and natural gas production facilities may also contain other VOC-
emitting units that include, but are not limited to, pumps, 
compressors, pneumatic devices, dehydrators, and engines. This rule 
does not contain requirements for, or otherwise apply to, those types 
of equipment. If we determine at a later date that there is a need for 
legally and practicably enforceable control of VOC emissions from 
additional equipment at these oil and natural gas production 
facilities, or for legally and practicably enforceable control of 
additional regulated NSR pollutant emissions, we may propose additional 
FIPs or propose supplements to this FIP.
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    \8\ The Bakken Pool is defined as a compilation of crude oil 
formations consisting of Bakken, Sanish and Three Forks formations.
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B. Purpose of the Rule

    As noted above, promulgating these Federal regulations addresses an 
important initial step to fill a regulatory gap with regard to 
controlling VOC emissions from oil and natural gas operations on the 
FBIR. There is no other Federal rule, including the recently finalized 
NSPS and NESHAPs for the Oil and Gas Sector (NSPS OOOO and NESHAP 
HH),\9\ that fills this gap for

[[Page 48882]]

the particular geologic formations that exist on the FBIR. This is in 
contrast to oil and natural gas operations off the Reservation which 
are governed by the NDDoH regulations and NDIC regulations previously 
discussed. As a result of these regulations, oil and natural gas 
operators in NDDoH jurisdiction are provided mechanisms for 
establishing legally and practicably enforceable control requirements 
that reduce VOC emissions and allow them, in most cases, to forgo time 
consuming and costly preconstruction permitting requirements before 
being able to start operations while helping to protect air quality and 
prevent fires, thus addressing the two concerns that we noted above 
have justified this final rule.
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    \9\ The requirements in NSPS OOOO and revised NESHAP HH were 
finalized on April 17, 2012, but not yet promulgated and can be 
found at http://www.epa.gov/airquality/oilandgas/actions.html, until 
such time that the final rule is published in the Federal Register.
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    What we are providing in the way of regulations in the FIP, and the 
impact that it will have on permitting is generally consistent with the 
approach that we have approved of in the areas surrounding the FBIR. 
Owners and operators of oil and natural gas operations in the NDDoH 
jurisdiction producing from the Bakken Pool are potentially subject to 
the North Dakota preconstruction permitting requirements found in the 
North Dakota Air Pollution Control Rules (``North Dakota Rules'') at 
Chapter 33-15-14 (Designated Air Contaminant Sources, Permit to 
Construct, Minor Source Permit to Operate, Title V Permit to Operate) 
and Chapter 33-15-15 (Prevention of Significant Deterioration of Air 
Quality) if uncontrolled emissions are greater than the permitting 
thresholds. However, all of the owners and operators are also subject 
to the North Dakota Rules for the operation of oil and natural gas 
production operations in the State of North Dakota. The regulations 
found at Chapter 33-15-07 (Control of Organic Compound Emissions) 
provide legally and practicably enforceable control requirements and 
VOC emission reductions when applicable. Additionally, all of the 
owners and operators are subject to the NDIC regulations for well 
completions found at Chapter 38-08 Control of Oil and Gas Resources. In 
many cases, owners and operators complying with these additional North 
Dakota Rules and NDIC regulations, and following the NDDoH guidance 
(Bakken Pool Guidance) \10\ do not have to obtain preconstruction 
permits from the NDDoH and can begin construction in a timelier manner.
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    \10\ Bakken Pool Oil and Gas Production Facilities Air Pollution 
Control Permitting & Compliance Guidance, NDDoH Air Quality 
Division, May 2, 2011. This guidance document was developed by the 
Bakken VOC Task Force. The Bakken VOC Task Force was a collaboration 
between the NDDoH and the owners and operators of oil and gas 
operations producing from the Bakken Pool.
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    Similar to the owners and operators of oil and natural gas 
operations producing from the Bakken Pool in NDDoH jurisdiction, the 
owners and operators of oil and natural gas operations producing from 
the Bakken Pool on the FBIR are potentially subject to the Federal 
preconstruction permitting requirements found in the Federal rules at 
40 CFR 52.21 (Prevention of Significant Deterioration of Air Quality), 
and 40 CFR 49.151 through 49.161 (Federal Tribal NSR Rule). However, on 
the FBIR only NSPS OOOO and NESHAP HH provide legally and practicably 
enforceable VOC control requirements outside of the Federal pre-
construction permitting requirements. Further, NSPS OOOO only applies 
to new and modified facilities and only to the oil storage tanks being 
utilized in the Bakken Pool operations. Thus, most owners and operators 
of oil and natural gas activities producing in the Bakken Pool must 
obtain preconstruction permits before production can begin, or if they 
are not obligated to obtain a permit face no control obligations 
whatsoever.
    This rule will fill this regulatory gap. Consistent with the 
regulatory structure that exists off the FBIR, and NSPS OOOO, this rule 
requires VOC control requirements and emissions reductions, monitoring, 
recordkeeping and reporting with regard to well completions, 
recompletions, and production and storage operations. This rule will 
also, to the extent practicable, minimize the construction permitting 
program implementation burdens upon us and the regulated community 
while establishing requirements that are unambiguous and legally and 
practicably enforceable.
    However, this rule will not eliminate any potential permitting 
requirements for oil and natural gas production facilities, but in many 
cases it will impose legally and practicably enforceable requirements 
that will lower PTE to a level that will allow the operators to 
construct without being required to obtain a PSD or Federal 
preconstruction permit under the Federal Tribal NSR Rule for Indian 
country. Specifically, where compliance with the requirements of this 
rule results in PTE VOCs from all pollution-emitting sources at the 
facility that are less than the thresholds in the PSD and Federal 
Tribal NSR rules, the source would not trigger permitting requirements 
and therefore may avoid PSD and minor source preconstruction permitting 
altogether. To comply with the CAA and avoid PSD or minor source 
preconstruction permitting altogether, a facility must calculate its 
PTE VOCs from all pollution-emitting sources at the facility and verify 
that it is less than the threshold in the PSD and Federal Tribal NSR 
rules. While we believe that VOC is the pollutant most likely to be 
emitted in quantities sufficient to require permitting, the facility 
may not avoid the PSD and Federal Tribal NSR permitting requirements if 
its emissions of any other regulated NSR pollutant are high enough to 
trigger PSD requirements.
    Included in the docket for this rule are copies of the NDDoH rules 
and guidance and the NDIC regulations that we considered in this 
process, as well as a technical support document explaining the 
requirements as compared to these requirements.

C. Development of the Rule

    We developed this rule in consultation with the Three Affiliated 
Tribes of the Mandan, Hidatsa, and Arikara Nation. As part of this 
consultation we evaluated the oil and natural gas activities and 
sources of VOC emissions that could impact air resources on the 
Reservation and the differences in the VOC emission reduction 
requirements for those facilities operating on the FBIR compared to 
those facilities operating in NDDoH jurisdiction. We also held a 
meeting with the Three Affiliated Tribes of the Mandan, Hidatsa, and 
Arikara Nations on June 13, 2012.
    To develop this rule, we first determined that oil and natural gas 
production on the FBIR from the Bakken Pool was becoming increasingly 
prevalent and that information regarding the nature of the fluids 
produced from the Bakken Pool indicated significant emissions of VOC. 
We accomplished this step by reviewing information provided by the 
NDDoH and a host of oil and natural gas operators already producing in 
the Bakken Pool.\11\
---------------------------------------------------------------------------

    \11\ The information reviewed was contained in synthetic minor 
NSR applications submitted to EPA, which are included in the docket 
for this rule.
---------------------------------------------------------------------------

    In order to develop appropriate requirements for the control of 
emissions from the production operations in the Bakken Pool, we studied 
the nature of the hydrocarbon liquids being produced and existing 
operations currently in practice. An oil well produces predominantly 
crude oil,

[[Page 48883]]

with some natural gas dissolved in it. Each crude oil reservoir has a 
combination of chemical and physical qualities which makes it unique. 
Some crude oil types are ``heavy'' (high viscosity and gravity 
containing very little associated natural gas) and some ``light'' (low 
viscosity and gravity containing high amounts of associated natural 
gas). The crude oil from the Bakken Pool is a light crude oil. It 
contains a higher amount of lighter hydrocarbon components than is seen 
in heavy crude oil, and therefore has greater potential to produce 
natural gas in addition to oil. Because of this characteristic, the 
production of crude oil from the Bakken Pool wells is similar to the 
production of natural gas liquids from natural gas wells. Natural gas 
liquids contain lighter end hydrocarbons such as ethane, propane, 
butane, and pentane, and methane gas. In addition, methods used to 
extract the hydrocarbons from both natural gas wells and the Bakken 
Pool wells produce hydrocarbon liquids that also contain water. 
Therefore, similar to natural gas well production, the production 
methods in the Bakken Pool involve the separation of the produced 
liquid into hydrocarbon liquids (oil), natural gas and water.
    The oil/natural gas/water emulsion being produced from each well is 
transported up the wellbore using an electric lifting unit, when 
required. The emulsion from the wells producing to this facility is 
transported through 2-phase separators (separators) which are an 
inherent component of the pipeline. The number of separators on any one 
production pipeline can vary from one to several. These separators 
reduce the pressure of the oil/natural gas/water emulsion to initiate 
the separation of the natural gases from the liquids. The natural gases 
and liquids are then sent to a 3-phase separator (heater-treater). The 
heater-treater reduces the pressure closer to ambient pressure and 
heats the leftover emulsion using a flame-arrested line heater (the 
heater-treater burner). The combination of higher temperatures and 
lower pressures allows for additional separation of the natural gas/
oil/water phases from each other because of differences in densities.
    Following the heater-treater, the produced oil and water are routed 
to storage tanks. The recovered natural gas is transferred from the 
heater-treater to the sales natural gas pipeline or to an emissions 
control unit when a natural gas sales pipeline is not available or the 
pipeline has a limited capacity. The oil is temporarily stored in these 
on-site storage tanks prior to being transferred either to tanker 
trucks or to a lease automatic custody transfer (LACT) unit for 
conveyance to a refining process plant. Separated water is temporarily 
stored in the on-site storage tanks prior to being loaded into tanker 
trucks for transport and disposal.
    In addition to the natural gas recovered from the extracted 
wellhead fluids, low pressure natural gas is also collected from off-
gassing that occurs from the storage of the produced oil and water in 
the on-site tanks at the facilities. This low pressure natural gas is 
collected via a vent line from the tanks and is either routed to an 
enclosed combustor, utility flare or pit flare for combustion, or is 
routed to a vapor recovery unit (VRU) to be injected into a natural gas 
sales pipeline for conveyance to a natural gas plant. In the event that 
pipeline injection of recoverable natural gas is temporarily infeasible 
and no enclosed combustor or utility flare is operational onsite, the 
natural gas may temporarily be routed through a closed-vent system to a 
pit flare.
    We further identified, in the information provided, that the most 
prevalent sources of VOC emissions associated with oil and natural gas 
production come from well completions, recompletions, and production 
and storage operations. During well completions and recompletions there 
is a period of flowback of oil, natural gas, and water from newly 
drilled wells in order to expel drilling and reservoir fluids which 
vents considerable VOC emissions to the atmosphere. Large amounts of 
VOCs are also emitted during production when the reservoir fluids are 
separated into oil, natural gas and water under high pressure using 
heat. Finally, the transfer and storage of the produced oil and water 
after separation can be a source of VOC emissions if vented to the 
atmosphere. In other words, the separated oil and water are both under 
high pressure and still contain some dissolved natural gas. When the 
separated oil and water are subjected to atmospheric pressure during 
transfer to storage tanks, the dissolved natural gas comes out of the 
liquid. Unless a natural gas sales pipeline is available and is used to 
receive the evolved natural gas, it becomes a significant source of VOC 
emissions. Due to the high levels of VOC emissions from these specific 
operations, we established VOC control and emission reduction 
requirements in this rule for completion and recompletion operations, 
heater-treater systems associated with production operations, and 
storage tanks associated with oil and water storage operations.
    Because of the experience that already existed in the Bakken Pool, 
we consulted with the owners and operators that are currently producing 
from the Bakken Pool on the FBIR and in NDDoH jurisdiction with regard 
to the production practices already in place. The practices currently 
in place are primarily due to product recovery or safety concerns and 
demonstrate compliance with the applicable NDIC regulations for flaring 
of co-produced natural gas and safety that address those concerns. 
These consultations provided us not only with information on the 
production on and off the Reservation, but also provided us with 
information on the existing phased approach to controlling practices 
occurring both from well completion and recompletions, through 
production operations, and ending with storage and loading operations 
and an appropriate timeline for installation of the controls. 
Components of this rule are based on these practices that are already 
in place off the FBIR.
    In addition, we evaluated the North Dakota regulations to help 
identify appropriate requirements for construction and operation of the 
regulated equipment and the requirements for controlling VOC emissions 
from this equipment. The North Dakota Rules at Chapter 33-15-07 provide 
requirements for the construction and operation of units that separate 
volatile organic liquids from water, and the control of VOC emissions 
from such units. Specifically, Chapter 33-15-07 requires that any 
equipment processing, treating, storing or handling volatile organic 
liquids must be equipped with covers (in the case of tanks), closed 
vent systems and control devices, such as VRUs, enclosed combustors, or 
flares. Chapter 33-15-07 refers to the Standards of Performance for VOC 
Emissions from Petroleum Refinery Wastewater Systems at 40 CFR 60.690 
for the control requirements and the requirements are appropriate to 
crude oil production operations. Chapter 33-15-07 requires the use of 
submerged pipe filling during storage operations to limit the evolution 
of natural gas from the oil and water. We determined that the VOC 
emission reduction requirements during the separation of the oil, 
natural gas, and water in this rule were relevant and appropriate as a 
basis for this rule. The North Dakota Rules at Chapter 33-15-20 provide 
requirements for the construction and operation of oil and natural gas 
production equipment and the control of VOC emissions from this 
equipment. Chapter 33-15-20 includes

[[Page 48884]]

requirements for storage tanks, separators and heater-treaters. While 
the North Dakota Rule only applies to oil or natural gas well 
production operations which emit sulfur or sulfur compounds to the 
atmosphere, we determined that the construction and control 
requirements were relevant and appropriate as a basis for this rule.
    We also reviewed the NDIC regulations and the Bakken Pool Guidance. 
The NDIC regulations found in the Control of Oil and Gas Resources at 
Chapter 38-08 require natural gas from the heater-treaters to be routed 
to a natural gas gathering pipeline as soon as practicable. When a 
pipeline is not available, heater-treater natural gas is required to be 
routed to a control system or device. The Bakken Pool Guidance details 
the air pollution control requirements of oil and natural gas 
operations producing from the Bakken Pool and provides an approach that 
may be used by owners and operators of oil and natural gas operations 
producing from the Bakken Pool to demonstrate compliance with the 
applicable North Dakota Rules. VOC control requirements have been 
established within this guidance for tank emissions and heater-treater 
systems and much of the control equipment requirements and monitoring 
requirements in this rule were adapted from this guidance. Control of 
VOC emissions from other sources such as dehydration units, pneumatic 
controllers, pneumatic pumps, truck loading, etc. are also included in 
this guidance; however, we did not evaluate those components of oil and 
natural gas production operations. NDDoH identifies acceptable control 
systems that may be used by the owners and operators. These systems 
include: a ground pit flare for tank and heater-treater emissions with 
an assumed 90.0 percent VOC destruction efficiency; a VRU for tank 
emissions, designed and operated to reduce the mass content of VOC 
emission by at least 99.0 percent; and an enclosed combustor or utility 
flare for tank and heater-treater emissions designed and operated to 
reduce the mass content of VOC emission by at least 98.0 percent. 
Heater-treater natural gas must be routed to a natural gas gathering 
pipeline as soon as practicable. In addition, to VOC control 
requirements, the guidance provides extensive operating and monitoring 
requirements for the controls. According to the owners and operators 
that are producing from the Bakken Pool on the FBIR, they are already 
voluntarily following this guidance in the FBIR. Therefore, we 
determined that the VOC emission reduction requirements in this 
document were relevant and appropriate as a basis for establishing 
monitoring, recordkeeping and reporting requirements necessary for 
enforceability of this rule.
    We also reviewed NSPS OOOO, which provides standards for oil and 
natural gas production from natural gas wells. However, with the 
exception of storage tanks and pneumatic controls, none of the 
production operations from the oil wells in the Bakken Pool that are 
covered by this rule are covered by NSPS OOOO. While this standard does 
not regulate the completion, recompletion, or production operations for 
the operations producing from the Bakken Pool, the common 
characteristics between natural gas production and the Bakken Pool 
production and the regulatory requirements specific to completion and 
recompletion, provided insight into feasible control requirements for 
these operations. In addition, the monitoring, recordkeeping and 
reporting requirements for production and storage operations were 
reviewed, and for necessary conditions to ensure legal and practicable 
enforceability were included in this rule. Some of the enhancements to 
the enforceability of the VOC reductions in this rule are derived from 
this standard.
    Although we view the most relevant regulatory analogue to those 
operations that are in NDDoH's jurisdiction and producing from the 
Bakken Pool, we also reviewed other state oil and natural gas 
production-related regulations for areas that are similar to North 
Dakota in industry, meteorology, or air quality concerns to ensure the 
proposed requirements are legally and practicably enforceable, as well 
as reasonably achievable, because the technologies are being commonly 
used and regulated.
    The other state air pollution agencies' rules and/or guidance that 
we reviewed included: Montana Department of Environmental Quality 
(MDEQ),\12\ Wyoming Department of Environmental Quality Air Quality 
Division (WDEQ),\13\ Colorado Department of Public Health and 
Environment Air Pollution Control Division (CDPHE) \14\ and the Utah 
Department of Environmental Quality (UDEQ).\15\ We also reviewed the 
regulations for oil and natural gas production facilities under the 
Texas Administrative Code, implemented by the Railroad Commission of 
Texas, Oil and Gas Division (RCT),\16\ the New Mexico Environment 
Department Air Quality Bureau (NMED),\17\ and the Oklahoma Department 
of Environmental Quality Air Quality Division (ODEQ).\18\ However, we 
determined that it was not relevant to review state and local rules 
that are intended to address non-VOC pollutant emissions, nonattainment 
area requirements or specific localized air quality concerns unless 
such concerns are also present on the FBIR or control equipment 
requirements apply to the same emission units this rule seeks to 
address. Copies of all the state and local agency rules that we 
considered in this process and other supporting documentation are 
included in the docket for this rule.
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    \12\ MDEQ. Chapter 8 Air Quality Subchapter 16 Emission Control 
Requirements for Oil and Gas Well Facilities Operating Prior to 
Issuance of a Montana Air Quality Permit. Available online at: 
http://www.deq.mt.gov/dir/legal/chapters/CH08-16.pdf. Accessed May 
29, 2012. State only rule.
    \13\ WDEQ Air Quality Division. Oil and Gas Production 
Facilities Chapter 6, Section 2 Permitting Guidance. Available 
online at: http://deq.state.wy.us/aqd/Oil%20and%20Gas/March%202010%20FINAL%20O&G%20GUIDANCE.pdf. Accessed May 29, 2012. 
State only guidance.
    \14\ Colorado Department of Health and Environment Air Pollution 
Control Division. Air Quality Control Commission Regulation Number 
7--Control of Ozone Via Ozone Precursors (Emissions of Volatile 
Organic Compounds and Nitrogen Oxides) 5-CCR 1001-9. Available 
online at: http://www.cdphe.state.co.us/regulations/airregs/5CCR1001-9.pdf. Accessed May 29, 2012. State only rule.
    \15\ Utah Administrative Code, Rule R307-327 Ozone Nonattainment 
and Maintenance Areas--Petroleum Liquid Storage, and Rule R649-3 
Drilling and Operating Practices. Utah Division of Administrative 
Rules. Available online at: http://www.rules.utah.gov/publicat/code.htm. Accessed May 29, 2012. State only rule.
    \16\ Texas Administrative Code, Title 16 Economic Regulation, 
Part 1 Railroad Commission of Texas, Chapter 3 Oil and Gas Division. 
Utah Texas Secretary of State. Available online at: http://www.sos.state.tx.us/tac/. Accessed May 29, 2012. State only rule.
    \17\ New Mexico Administrative Code, Title 20 Environmental 
Protection, Chapter 2 Air Quality, Part 38 Hydrocarbon Storage 
Facilities and Part 61 Smoke and Visible Emissions. New Mexico 
Commission of Public Records, New Mexico Register. Available online 
at: http://www.nmcpr.state.nm.us/nmac/_title20/T20C002.htm. 
Accessed May 29, 2012. State only rule.
    \18\ Oklahoma Administrative Code, Title 252 Department of 
Environmental Quality, Chapter 100 Air Pollution Control, Subchapter 
37 Control of Volatile Organic Compounds. Oklahoma Secretary of 
State--Office of Administrative Rules. Available online at: http://www.sos.ok.gov/oar/online/viewCode.aspx. Accessed May 29, 2012. EPA 
approved SIP sections include: 252:100-37-1, 252:200-37-3, 252:100-
37-4, 252:100-37-5, 252:100-37-15, 252:100-37-16, 252:100-37-26, 
252:100-37-35, 252:100-37-36, 252:100-37-37, 252:100-37-41, and 
252:100-37-42; State only rule sections include: 252:100-37-2, 
252:100-37-17, 252:100-37-18, 252:100-37-25, and 252:100-37-
38[Revoked].
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    Regarding state regulations and guidance for VOC destruction 
efficiency and monitoring of enclosed combustors and utility flares, 
the rule requirements

[[Page 48885]]

are generally consistent with all state requirements for enclosed 
combustors and utility flares.
    When reviewing state regulations or guidance for produced oil and 
water storage tanks, we focused on those that might apply to the tank 
sizes that are typically constructed at oil and natural gas production 
facilities on the FBIR, primarily tanks with a storage capacity of 500 
bbl each or less (approximately 21,000 gallons). The requirements for 
construction and emission control of produced oil and water storage 
tanks are fairly consistent with all state regulations and guidance 
reviewed, although there are varying degrees of de minimis natural gas 
throughput, storage capacities, or annual flashing emissions below 
which the requirements do not apply or the control equipment may be 
removed. The WDEQ requires 98 percent VOC reduction for tanks with a 
PTE greater than 10 tons per year (tpy) within 60 days of the first 
date of production, compared to ninety (90) days in this rule. The WDEQ 
also allows control equipment removal if flashing emissions decline to 
and are reasonably expected to remain below 8 tpy. We do not provide 
any de minimis throughput or storage capacities below which the 
requirements in this rule do not apply; however, as discussed 
previously, we allow owners or operators to use 90.0 percent control 
equipment after one year after the first date of production if the 
uncontrolled PTE VOCs emissions from the aggregate of all produced oil 
storage tanks and any produced water storage tanks interconnected with 
the produced oil storage tanks declines to less than 20 tpy.

D. Area and Facilities Covered by the FIP

    This rule will apply to any person who owns or operates an existing 
(constructed or modified on or after August 12, 2007), new, or modified 
oil and natural gas production facility \19\ producing from the Bakken 
Pool and located on the FBIR as set forth in 40 CFR Part 49, Subpart 
141--Reservation-Specific FIP for Oil & Natural Gas Production 
Facilities; FBIR. A more detailed description of the Reservation is 
provided below in Section IV.
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    \19\ For the purposes of this rule, an oil and gas production 
facility consists of all the air pollution emitting units and 
activities located on or integrally connected to one or more oil and 
gas wells that are necessary for production and separation of 
reservoir fluids, temporary storage of produced and produced water, 
and preparation of the produced oil, produced water, and produced 
gas for transport off-site. Additionally, August 12, 2007 is the 
earliest well completion date identified in the CAFOs.
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    This rulemaking is a step in addressing concerns that have been 
raised about the potential impacts due to increasing oil and natural 
gas development on the FBIR. If in the future, we become aware of air 
quality or permitting burden related to oil and natural gas production 
for other Reservations or areas of Indian Country, using our authority 
described in Section V. of this notice, we may propose other FIPs that 
are deemed necessary or appropriate.

E. Effect on Permitting of Facilities

    This rule is not a permitting program. It therefore does not impose 
or exempt the facilities from any Federal CAA permitting requirements, 
including the PSD preconstruction permitting requirements at 40 CFR 
Sec.  52.21 or Federal Tribal NSR Rule permitting requirements for 
minor sources at 40 CFR 49.151. The purpose of this rule is to provide 
legal and practical enforceability for the use of VOC emission controls 
that are already being used voluntarily by the industry and for VOC 
emissions reductions from those controls. Provided that the facilities 
are in compliance with the new rule, they may take into account the 
enforceable VOC emission reductions from the required controls they use 
when calculating their PTE for determining applicability of the 
permitting requirements, to the extent that the effect those controls 
would have on VOC emissions is legally and practicably enforceable.
    Regardless of this rule, some facilities' PTE VOCs or any other 
regulated NSR pollutant may exceed the applicability thresholds for PSD 
or Federal Tribal NSR Rule permitting even after applying the legally 
and practicably enforceable emission reductions provided in this rule. 
In such cases, the owners or operators of these facilities are required 
to apply for and obtain the appropriate permits.

F. Registration Requirements

    This rule does not exempt facilities located on the FBIR from the 
registration requirements of the Federal Tribal NSR Rule, promulgated 
on July 1, 2011. Nor does this rule impose any additional registration 
requirements. Again, the purpose of this rule is to provide legal and 
practical enforceability for the use of VOC emission controls that are 
already being used as an industry standard and for VOC emissions 
reductions from those controls. Provided that the facilities are in 
compliance with the provisions of this rule, facilities may include the 
enforceable VOC emission reductions resulting from the controls 
required in this rule when calculating their PTE, to the extent that 
the effect those controls would have on VOC emissions is legally and 
practicably enforceable.
    If the PTE VOCs or any other regulated NSR pollutant is less than 
the major source thresholds in 40 CFR 52.21, but equal to or greater 
than the thresholds in the Federal Tribal NSR Rule, then registration 
is required of these facilities (40 CFR 49.160). Those facilities that 
must obtain a PSD permit pursuant to 40 CFR 52.21 or wish to obtain a 
preconstruction permit pursuant to 40 CFR 49.151 of the Federal Tribal 
NSR Rule, in addition to meeting the requirements of this rule, are 
exempt from this registration requirement.

G. Applicability to New and Existing and Modified Facilities

    This rule applies to each owner or operator constructing or 
operating an oil and natural gas production facility that is located on 
the FBIR and producing from the Bakken Pool with one or more oil and 
natural gas wells, any one of which a well completion or recompletion 
operation is/was initiated on or after August 12, 2007.
    For the purposes of this rule, a well completion means the process 
that allows for the flowback of oil and natural gas from newly drilled 
wells to expel drilling and reservoir fluids and tests the reservoir 
flow characteristics, which may vent produced hydrocarbons to the 
atmosphere via an open pit or tank. A well completion operation means 
any oil and natural gas well completion with hydraulic fracturing 
occurring at an oil and natural gas production facility. The completion 
date is considered the date that construction at an oil and natural gas 
production facility has commenced. A well recompletion operation means 
any oil and natural gas well completion with hydraulic refracturing 
occurring at an oil and natural gas production facility. The 
recompletion date is considered the date that a modification has 
occurred at an oil and natural gas production facility. The reason we 
selected the initiation of completions operations as the date for 
defining a new facility is that owners and operators use drill rigs 
prior to initial completion operations and this equipment is not 
considered a stationary source. In addition, it is not certain during 
the drilling operations whether a well will be a producing well. Hence 
it is not known whether an oil and natural gas production facility will 
be constructed to support that well. The outcome of a completion 
operation provides the well owners and operators information necessary 
to determine whether an oil and gas production

[[Page 48886]]

facility will be constructed. Requiring compliance with this rule upon 
recompletion of any one well at a facility is consistent with NSPS 
OOOO. According to the final NSPS OOOO notice, a completion operation 
associated with refracturing is considered a modification under CAA 
section 111(a), because physical change occurs to the well resulting in 
emissions increases during the recompletion operation (for the purposes 
of this rule the process of refracturing is defined as a recompletion).
    In determining the appropriate effective date and the well 
completion dates for this rule, we evaluated the purpose of the rule, 
the gaps in regulations, NSPS OOOO and the requirements and 
stipulations of CAFOs finalized between us and select operators on the 
FBIR in late August 2011 and amended, in some cases, between then and 
July 2012. The August 12, 2007, date is the earliest well completion 
date identified in the CAFOs. These orders established control 
requirements during the life of the orders for facilities operating on 
the FBIR by these companies who voluntarily entered into the agreement 
with us. One goal of this FIP for existing oil and natural gas 
production facilities is to provide a CAA compliance mechanism for 
those companies with CAFOs, prior to their expiration, which will occur 
between August 26, 2012 and August 31, 2012. Copies of all of the CAFOs 
can be found in the docket for the rule.

H. Attainment Status

    All counties in North Dakota that coincide with the FBIR are 
designated as unclassifiable/attainment for all criteria pollutants 
under the CAA. See 40 CFR 81.335.
    Current air quality conditions in the region of the FBIR and in 
western North Dakota are good, with measured ambient ozone \20\ and 
nitrogen dioxide (NO2) concentrations substantially lower 
than the current National Ambient Air Quality Standards (NAAQS) of 75 
parts per billion (ppb) for 8-hour average ozone and 100 ppb for the 1-
hour average NO2. The state of North Dakota operates three 
air quality monitor sites in western North Dakota to characterize 
regional background air quality. At the Dunn Center monitoring site 
located, approximately 20 miles southwest of the of the FBIR, the 
current design values for the ozone and NO2 NAAQS are 55 ppb 
and 11 ppb, respectively.
---------------------------------------------------------------------------

    \20\ VOC and NOX are precursors to ozone.
---------------------------------------------------------------------------

    We evaluated the impacts of changes in VOC and nitrogen oxides 
(NOX) emissions from enclosed combustors and flares used for 
control of VOC emissions at oil and natural gas production facilities 
on the FBIR as part of the technical analysis for this rule. Emissions 
categories that are substantially controlled by this rule include VOC 
and NOX.
    Expected potential emissions of sulfur dioxide (SO2) and 
particulate matter (PM) pollutants from enclosed combustors and flares 
used for control of VOC emissions at well pads are estimated to be 
below the Federal Tribal NSR rule permitting thresholds, and are 
therefore expected to have insignificant impacts on the NAAQS for these 
pollutants. Expected potential emissions of carbon monoxide (CO) from 
enclosed combustors and flares used for control of VOC emissions at 
well pads are expected to have an insignificant impact on the CO NAAQS 
because of the level and form of the CO standard in comparison to the 
emissions.
    This rule establishes legally and practicably enforceable VOC 
emission reductions that reflect reductions that facilities are already 
routinely achieving through the installation and operation of control 
equipment for health, safety and market purposes. In addition, this 
rule does not exempt these facilities from other potentially applicable 
regulatory or permitting requirements. Therefore, we believe that air 
quality in this area will not be adversely impacted by this action.
    Supporting air quality information is discussed in the Technical 
Support Document for this rule, found in the rule docket.

I. Benefits and Costs

    Produced natural gas and natural gas emissions resulting from oil 
and natural gas production from the Bakken Pool underlying the FBIR 
have a high VOC content. Typically, the natural gases associated with 
the produced oil would be captured as product and injected directly 
into a natural gas sales pipeline. However, this is a relatively new 
field and while the natural gas sales pipelines are being developed, 
they are minimally available at this time. Currently, most produced 
natural gas and natural gas emissions from oil and natural gas 
production operations on the FBIR are routed to a combustion device 
such as a pit flare, utility flare, or enclosed combustor.
    Uncontrolled emissions of VOC from operations at an oil and natural 
gas production facility consisting of a single well and associated 
production and storage operations were estimated to average 
approximately 2,165 tons per year (tpy). Of this total, approximately 
1,610 tpy of VOC results from produced natural gas emissions from the 
heater-treater and 555 tpy of VOC is emitted from the produced oil and 
water storage tanks. This rule requires that emissions from the heater-
treater and the storage tanks be routed to a combustion device. We 
estimate that, on average, the control requirements in this rule will 
reduce VOC emissions from an oil and natural gas production facility by 
approximately 2,090 tpy per well.\21\
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    \21\ The Technical Support Document includes a more detailed 
explanation of benefits and costs. It can be found in the docket for 
the final rule, Docket ID: EPA-R08-OAR-2012-0479, which can be 
accessed at: http://www.regulations.gov (hereinafter referred to as 
TSD).
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    The costs of the control equipment required by this rule depend, in 
part, on the number of wells associated with each oil and natural gas 
production facility. Generally, as the number of wells located at oil 
and natural gas production facilities increase, the volume of oil and 
natural gas production and associated emissions also increase. Multiple 
wells at an oil and natural gas production facility can often share 
control equipment if there is sufficient capacity to handle the 
additional produced natural gas and natural gas emissions; thus, the 
costs of the control equipment per well potentially decreases at oil 
and natural gas production facilities that consist of multiple wells. 
The Bureau of Land Management (BLM) has estimated that future 
development in the area of North Dakota encompassing the FBIR is likely 
to feature an average of 1.5 wells per facility.\22\ Based on 
information from synthetic minor permit applications and environmental 
assessments conducted by the Bureau of Indian Affairs,\23\ we believe a 
value of two wells per facility provides a conservative estimate of 
well density for future development on the FBIR.
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    \22\ October 2, 2009 Bureau of Land Management (BLM) report 
titled ``Reasonable Foreseeable Development Scenario for Oil and Gas 
Activities on Bureau Managed Lands in the North Dakota Study Area.'' 
This report was supplemented on February 25, 2011 with the document 
titled ``Revised Activity and Surface Disturbance Projections for 
the Reasonable Foreseeable Development Scenario for Oil and Gas 
Activities on Bureau Managed Lands in the North Dakota Study Area''. 
Both documents are included in the docket for this rule and are 
publicly available at the following Web site:  http://www.blm.gov/mt/st/en/fo/north_dakota_field/rmp/RFD.html.
    \23\ See TSD at Section 4. Reasonably Foreseeable Development.
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    We calculated the total annual cost for a two-well facility 
utilizing a pit flare, utility flare, and two enclosed combustors as 
control equipment. For this operating scenario, we have

[[Page 48887]]

estimated that the total annual cost of compliance with this rule would 
be approximately $52,000 per facility. Using the estimated average of 
4,180 tpy VOC reduction from a facility consisting of two wells and 
associated production and storage operations, we calculated the cost 
effectiveness of this rule as less than $15 per ton VOC reduced.
    Based on the reasonably foreseeable development in the 2011 BLM 
supplemental report, we estimate that a maximum of 1,000 facilities may 
be developed on the FBIR by 2029. Applying a maximum total annual cost 
impact for a two-well facility of approximately $52,000, the maximum 
annual cost of compliance with this rule on the oil and natural gas 
industry is estimated to be approximately $50 million. However, we 
believe this is a conservative estimate and that actual annual costs 
would be much lower due to factors such as increased facility well 
density, standard industry practice to use VOC control equipment, and 
anticipated pipeline infrastructure development, which is explained 
further in the technical support document for this rule.

IV. The Fort Berthold Indian Reservation

    The Three Affiliated Tribes of the Mandan, Hidatsa, and Arikara 
Nations are a federally-recognized Indian tribe organized under a 
Constitution and By-Laws ratified by the Tribes on May 15, 1936 and 
approved by the Secretary of the Interior on June 29, 1936 (with 
relevant amendments to the Constitution and By-Laws approved by the 
Department of the Interior on March 11, 1985). See 75 FR 60813 (October 
1, 2010); Constitution and By-Laws of the Three Affiliated Tribes of 
the Mandan, Hidatsa, and Arikara Nations. The FBIR was established 
pursuant to the Treaty of Fort Laramie of 1851 and addressed in 
subsequent agreements and Executive Orders, including the Agreement at 
Fort Berthold, 1866, and Executive Orders in 1868, 1870 and 1880. As 
described in the Tribes' Constitution and By-Laws (and as approved by 
the Secretary of the Interior), the FBIR currently includes all lands 
within the exterior boundaries of the Reservation, which is defined by 
the Act of March 3, 1891 (26 Statute 1032) and which includes all lands 
added to the Reservation by Executive Order of June 17, 1892.
    Pursuant to CAA section 301(d), 42 U.S.C. 7601(d), we are 
authorized to treat eligible Indian tribes in the same manner as states 
(TAS) for purposes of implementing CAA provisions over their entire 
Reservation and over any other areas within their jurisdiction. See 63 
FR 7254-57 (February 12, 1998) (explaining that CAA section 301(d) 
includes a delegation of authority from Congress to eligible Indian 
tribes to implement CAA programs over all air resources within the 
exterior boundaries of their Reservations). The Three Affiliated Tribes 
have not applied for TAS for the purpose of administering a Tribal 
Implementation Plan (TIP) under the CAA. There is thus currently no 
EPA-approved plan implementing the functions and provisions of this FIP 
on the FBIR. The FIP the EPA is promulgating today fills this 
regulatory gap and applies to all lands on the FBIR, which is defined 
by the Act of March 3, 1891 (26 Statute 1032) and which includes all 
lands added to the Reservation by Executive Order of June 17, 1892.

V. EPA's Authority To Promulgate a FIP

    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 to treat Indian tribes in the same manner as states. 
Pursuant to this statutory directive, EPA promulgated regulations 
entitled, ``Indian Tribes: Air Quality Planning and Management'' (TAR) 
63 FR 7254 (February 12, 1998). Our regulations delineate the CAA 
provisions for which it is appropriate to treat tribes in the same 
manner as a state. See 40 CFR 49.3, 49.4. Among those provisions for 
which we determined such treatment was inappropriate are CAA section 
110(a)(1) (State Implementation Plan (SIP) submittal and implementation 
deadlines) and CAA section 110(c)(1) (directing EPA to promulgate a 
Federal Implementation Plan (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). 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 (February 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 
reasonable time.'' Id. (referencing Sec.  49.11(a) which provides that 
the Agency will promulgate a FIP to protect tribal air quality within a 
reasonable time if tribal efforts do not result in adoption and 
approval of tribal plans or program).\24\
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    \24\ Section 49.11(a) states that the Agency, ``[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.'' 40 CFR 49.11(a).
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    The preamble to the TAR set forth our view articulated in the 
proposed rule 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 our 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.
    The NDDoH, the CAA permitting authority for areas outside of Indian 
country, including outside of the FBIR, has promulgated rules to 
control emissions from oil and natural gas production facilities. Since 
there is not currently an approved FIP specifically covering the 
reduction of VOC emissions related to natural gas emissions from oil 
and natural gas production facilities on the FBIR, a regulatory gap 
exists with regard to such facilities operating within the exterior 
boundaries of the Reservation. This FIP will establish legally and 
practicably enforceable requirements to control and reduce VOC 
emissions. Therefore, in this rule, we determined that it is necessary 
and appropriate to exercise our discretionary authority under sections 
301(a) and 301(d)(4) of the CAA and 40 CFR 49.11(a) to promulgate a FIP 
to remedy an existing regulatory gap under the Act with respect to the 
FBIR.

VI. Summary of FIP Provisions

A. Applicability

    This rule applies to oil and natural gas facilities producing from 
the Bakken Pool that are constructed and operating on the FBIR in North 
Dakota on or after August 12, 2007. Specifically, this rule applies to 
facilities on the FBIR within the Crude Petroleum and Natural Gas 
Extraction Industry, North American

[[Page 48888]]

Industry Classification System (NAICS) Code 211111.

B. Compliance Schedule

    Compliance with the rule is required no later than November 13, 
2012 or upon initiation of completion or recompletion operations, 
whichever is later. Upon signature by the Administrator, we will post 
this rule on our Internet site (http://www.epa.gov/region8/air/fbirfip.html) and notify the owners and operators and the Tribes.

C. Provisions for Delegation of Administration to the Tribes

    The provisions in Sec.  49.141 establish the steps by which the 
Three Affiliated Tribes may request delegation to assist us with the 
administration of this rule and the process by which the Regional 
Administrator of EPA Region 8 may delegate to the Tribes the authority 
to assist with such administration of this rule. As described in the 
regulatory provisions, any such delegation will be accomplished through 
a delegation of authority agreement between the Regional Administrator 
and the Tribes. This section provides for administrative delegation of 
this federal rule and does not affect the eligibility criteria under 
CAA section 301(d) and 40 CFR 49.6 for TAS should the Tribes decide to 
seek such treatment for the purpose of administering their own EPA-
approved program under Tribal law. Administrative delegation is a 
separate process from TAS under the TAR. Under the TAR, Indian tribes 
seek EPA-approval of their eligibility to run CAA programs under their 
own laws. The Three Affiliated Tribes would not need to seek TAS under 
the TAR for purposes of requesting to assist us with administration of 
this rule through a delegation of authority agreement. In the event 
such an agreement is reached, the rule would continue to operate under 
federal authority throughout the FBIR, and the Tribes would assist us 
with administration of the rule to the extent specified in the 
agreement.

D. General Provisions

    The provisions in Sec.  49.142 General Provisions provide: (1) 
Definitions that apply to this rule; (2) assurance that we will 
maintain its authority to require testing, monitoring, recordkeeping, 
and reporting in addition to that already required by an applicable 
requirement, in a permit to construct or permit to operate in order to 
ensure compliance; and (3) assurance that nothing in the rule will 
preclude the use, including the exclusive use, of any credible evidence 
or information, relevant to whether a facility would have been in 
compliance with applicable requirements if the appropriate performance 
or compliance test had been performed.

E. Construction and Operational Control Measures

    The provisions in Sec.  49.143 Construction and Operational Control 
Measures provide requirements to reduce VOC emissions during well 
completion and recompletion operations. The owner or operator must 
route all casinghead natural gas emissions associated with completion 
and recompletion operations to a utility flare or a pit flare capable 
of reducing the mass content of VOCs in the natural gas vented to it by 
at least 90.0 percent. We note that the well completion and 
recompletion control requirements to use pit flares or utility flares 
that have the capability to reduce the mass content of VOC in the 
natural gas emissions routed to them by at least 90.0 percent by weight 
are the minimum level of control that would be allowed under this rule. 
Owners and operators may also choose to perform reduced emission 
completions and recompletions,\25\ which would exceed the 90.0 percent 
VOC emission reduction requirement. This section also requires the 
control of production and storage operations and imposes a timeline for 
installation of the controls on these operations. The owner or operator 
is required to reduce the mass content of VOC emissions from natural 
gas during oil and natural gas production and storage operations by at 
least 90.0 percent on the first date of production. Within ninety (90) 
days of the first date of production, we require the owner or operator 
to route the natural gas from the production and storage operations 
through a closed-vent system to a utility flare or equivalent 
combustion device capable of reducing the mass content of VOC in the 
natural gas vented to the device by at least 98.0 percent. The owner or 
operator also has the option to design their production and storage 
operations to recover the natural gas as product and inject it into a 
natural gas gathering pipeline system for sale or other beneficial 
purpose. For those owners or operators that choose to capture the 
natural gas as product rather than a pollutant to be controlled, the 
natural gas may temporarily be routed through a closed-vent system to 
an enclosed combustor, utility flare or pit flare in instances where 
injection of the product into the pipeline is temporarily infeasible. 
In these situations, the pit flare is considered an emergency standby 
unit used for unplanned flare events such as temporarily limited 
pipeline capacity, equipment breakdown and/or other upsets that are 
beyond a producer's control and the pit flare is used to safely burn 
the natural gas product that could otherwise pose a potential risk to 
workers, the community, or the environment. The owner or operator, 
however, must limit use of the pit flare in these instances to 500 
hours of operation in any consecutive 12-month period. This limit on 
the hours of operation of the pit flare in such situations provides a 
balance of air quality, safety and environmental protection, to address 
public concerns expressed on the proposed synthetic minor NSR permits 
with the use of pit flares, and flexibility for the operators, to 
address claims that continuous injection into a natural gas sales 
pipeline may not be possible at all times.
---------------------------------------------------------------------------

    \25\ U.S. Environmental Protection Agency. Lessons Learned from 
Natural Gas STAR Partners: Reduced Emissions Completions for 
Hydraulically Fractured Natural Gas Wells. Office of Air and 
Radiation: Natural Gas Star Program. Washington, DC. Available at: 
http://epa.gov/gasstar/documents/reduced_emissions_completions.pdf. Accessed July 26, 2012.
---------------------------------------------------------------------------

    The rule requires the owner or operator to route all standing, 
working, breathing and flashing losses from the produced oil storage 
tanks and any produced water storage tanks interconnected with the 
produced oil storage tanks through a closed vent system to either an 
operating system designed to recover and inject the natural gas 
emissions into a natural gas gathering pipeline system for sale or 
other beneficial use, or to an enclosed combustor or utility flare 
capable of reducing the mass content of VOC in the natural gas 
emissions vented to the device by at least 98.0 percent. We note that 
while NSPS OOOO requires 95% VOC reduction of emissions from storage 
tanks, owners and operators of oil and natural gas production 
facilities on the FBIR have indicated that a 98% VOC destruction 
efficiency in the Bakken Pool Guidance is achievable and committed in 
their synthetic minor NSR applications to reduce the mass content of 
VOC emissions routed to the enclosed combustors or utility flares used 
for storage tank control by at least 98.0% by weight. Since oil and 
natural gas production on the FBIR has higher VOC content than typical 
natural gas production and the overall BTU value is generally higher, 
this should result in more efficient VOC destruction. Therefore, we 
believe that a requirement of 98.0% reduction of VOC emissions during 
continued production operations is appropriate. However, to prevent 
duplicative federal requirements for

[[Page 48889]]

owners and operators of storage tanks on the FBIR subject to both this 
rule and NSPS OOOO, storage tanks subject to and controlled under the 
requirements specified in 40 CFR part 60, subpart OOOO are considered 
to meet the storage tank control requirements of this rule. No further 
requirements apply for such storage tanks under this rule. In addition, 
like the Bakken Pool Guidance, the rule provides that if the 
uncontrolled PTE VOCs from the aggregate of all produced oil storage 
tanks and produced water storage tanks interconnected with produced oil 
storage tanks at an oil and natural gas production facility is less 
than, and reasonably expected to remain below, 20 tons in any 
consecutive 12-month period, then the owner or operator may use a 
utility flare or enclosed combustor that is capable of reducing the 
mass content of VOC in the natural gas emissions vented to the device 
by only 90.0 percent upon written approval by the EPA.\26\
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    \26\ If the owner or operator receives written approval for a 
new method, the owner or operator must calculate potential to emit 
based on the new EPA-approved method.
---------------------------------------------------------------------------

    The requirements to use pit flares, enclosed combustors, and 
utility flares are based on requirements in the North Dakota Rules at 
Chapters 33-15-07 and 33-15-20, and the Bakken Pool Guidance. These 
control devices must be operated under specific conditions as specified 
in Sec.  49.144 Control Equipment Requirements and Sec.  49.145 
Monitoring Requirements. The VOC destruction efficiencies of 90.0 and 
98.0 percent are the same efficiencies required in the Bakken Pool 
Guidance.\27\

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    \27\ Based on our consultation with the owners and operators 
producing from the Bakken Pool, in addition to these particular 
provisions we also identified for regulating emissions from well 
completions and recompletions. These control operations are already 
being performed during these operations for product recovery or 
safety purposes. These consultations, provided us not only with 
information on the production practices occurring both on and off 
the Reservation, but it also provided us with information on the 
existing phased approach to controlling emissions from well 
completion and recompletions, through production operations, and 
ending with storage and loading operations and an appropriate 
timeline for installation of the controls. Those components in this 
section are based on these practices that are already in place.
---------------------------------------------------------------------------

F. Control Equipment Requirements

    The provisions in Sec.  49.144 Control Equipment Requirements 
require the use of covers on all produced oil and water storage tanks 
and the use of closed-vent systems with all VOC capture and control 
equipment. These requirements are derived from the North Dakota Rules 
at Chapter 33-15-07. Section 49.144 also specifies construction and 
operational requirements for the covers and closed-vent systems. The 
construction and operational requirements of the covers and closed-vent 
systems are based on the NSPS OOOO requirements and are intended to 
provide legal and practical enforceability. In addition, Sec.  49.144 
requires specific construction and operational requirements of pit 
flares, enclosed combustors, and utility flares. These requirements are 
derived from the Bakken Pool Guidance and have been enhanced where 
necessary to provide legal and practical enforceability.
    The provisions in Sec.  49.144 require that each owner and operator 
equip the openings on each produced oil storage tank and each produced 
water storage tank that is interconnected with produced oil storage 
tanks with a cover that ensures that natural gas emissions are 
efficiently routed through a closed-vent system to a vapor recovery 
system, an enclosed combustor, or a utility flare. Each cover and all 
openings on the cover (e.g., access hatches, sampling ports, and gauge 
wells) must form a continuous barrier over the entire surface area of 
the produced oil and produced water in the storage tank. Each cover 
opening must be secured in a closed, sealed position (e.g., covered by 
a gasketed lid or cap) whenever material is in the tank on which the 
cover is installed except during those times when it is necessary to 
use an opening as follows: (1) To add material to, or remove material 
from the unit (this includes openings necessary to equalize or balance 
the internal pressure of the unit following changes in the level of the 
material in the unit); or (2) to inspect or sample the material in the 
unit; or to inspect, maintain, repair, or replace equipment located 
inside the unit. These requirements are consistent with the 
requirements for storage tanks under NSPS OOOO and will ensure that the 
requirements apply to any storage tanks that are not subject to NSPS 
OOOO.
    Each owner and operator is required to use closed-vent systems to 
collect and route natural gas emissions to the respective VOC control 
devices. All vent lines, connections, fittings, valves, relief valves, 
or any other appurtenance employed to contain and collect gases, and 
transport them to the VOC control equipment must be maintained and 
operated properly during any time the control equipment is operating 
and must be designed to operate with no detectable natural gas 
emissions. If a closed-vent system contains one or more bypass devices 
that could be used to divert all or a portion of the natural gas, from 
entering the VOC control devices, the owner or operator must meet one 
of the following options for each bypass device: (1) At the inlet to 
the bypass device properly install, calibrate, maintain, and operate a 
natural gas flow indicator capable of taking periodic readings and 
sounding an alarm when the bypass device is open such that the natural 
gas is being, or could be, diverted away from the control device and 
into the atmosphere; or (2) secure the bypass device valve in the non-
diverting position using a car-seal or a lock-and-key type 
configuration. These requirements are consistent with the requirements 
for storage tanks under NSPS OOOO and will ensure that the requirements 
apply to any storage tanks that are not subject to NSPS OOOO.
    Each owner or operator is required to follow the manufacturer's 
written operating instructions, procedures and maintenance schedule to 
ensure good air pollution control practices for minimizing emissions 
from each enclosed combustor or utility flare. Each enclosed combustor 
must have the capacity to reduce the mass content of the VOC in the 
natural gas routed to it by at least 98.0 percent for the minimum and 
maximum natural gas volumetric flow rate and British Thermal Unit (BTU) 
content routed to it. We note that the NSPS OOOO requires owners and 
operators to demonstrate that enclosed combustors and utility flares 
achieve the required VOC reduction by conducting performance tests. 
Those units that have been tested by the manufacturer in accordance 
with specific requirements in the rule, or that are designed and 
operated in accordance with applicable requirements in 40 CFR 60.18(b), 
satisfy the requirements of performance testing by the owner or 
operator. For the purposes of this rule, we require that all utility 
flares installed per this rule meet the requirements in 40 CFR 
60.18(b), and all enclosed combustors installed per this rule must be 
tested according to the NSPS OOOO performance testing requirements. 
Until such time that compliance is required with the storage vessel 
requirements in the NSPS OOOO standard, however, the owner or operators 
can demonstrate compliance using methods specified in this rule.
    We determined that certain work practice and operational 
requirements are also necessary for the practical enforceability of the 
VOC emission reduction requirement that the enclosed combustors or 
utility flares must achieve. Flares and combustors must be operated 
within specific parameters to effectively destroy VOC emissions. This 
was discussed in great detail in the preamble and technical support

[[Page 48890]]

documents to the proposed and final NSPS OOOO \15\. Therefore, each 
owner or operator must ensure that each enclosed combustor or utility 
flare is: (1) Operated at all times that natural gas is routed to it; 
(2) operated with a liquid knock-out system to collect any condensable 
vapors (to prevent liquids from going through the control device); (3) 
equipped with a flash-back flame arrestor; (4) equipped with a 
continuous burning pilot flame and thermocouple, or equipped with an 
electronically controlled automatic ignition system; (5) equipped with 
a malfunction alarm and remote notification system to detect if the 
pilot flame fails while natural gas is being routed through the device; 
(6) equipped with a continuous recording device, such as a chart 
recorder, data logger or similar device, or connected to a Supervisory 
Control and Data Acquisition (SCADA) system, to monitor and document 
proper operation of the enclosed combustor or utility flare; (7) 
maintained in a leak free condition; and (8) operated with no visible 
smoke emissions. These requirements are consistent with Bakken Pool 
Guidance.
    Section 49.144 requires that each owner or operator limit the use 
of pit flares to: the control natural gas emissions during well 
completion operations; the control VOC emissions in the event the 
natural gas that is being recovered for sale or other beneficial 
purpose must be diverted to an emergency control device because 
injection into the pipeline is temporarily infeasible and the enclosed 
combustor or utility flare installed at the oil and natural gas 
production facility is not operational; or use when total uncontrolled 
PTE VOCs from all produced oil storage tanks and any produced water 
storage tanks interconnected with produced oil storage tanks at an oil 
and natural gas production facility have declined to less than, and are 
reasonably expected to stay below, 20 tons in any consecutive 12-month 
period. Each pit flare must be operated to reduce the mass content of 
VOC in the natural gas routed to it by at least 90 percent and must be 
operated with no visible smoke emissions.\28\ Each pit flare must be 
equipped with an electronically controlled automatic ignition system 
with malfunction alarm and remote notification system if the pilot 
flame fails. Each pit flare must be visually inspected for the presence 
of a pilot flame any time natural gas is being routed to it and if the 
pilot flame fails, it must be relit as soon as safely possible and the 
automatic ignition system must be repaired or replaced before the pit 
flare is used again.
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    \28\ Owners and operators of oil and natural gas production 
facilities on the FBIR have indicated that a 90.0% VOC destruction 
efficiency in the Bakken Pool Guidance is achievable using a pit 
flare and committed in their synthetic minor NSR applications to 
reduce the mass content of VOC emissions routed to a pit flare by at 
least 90.0% by weight.
---------------------------------------------------------------------------

    As North Dakota has done in the Bakken Pool Guidance, Sec.  49.144 
allows owners or operators of oil and natural gas production facilities 
to use control devices other than an enclosed combustor or utility 
flare, provided they are capable of achieving at least a 98.0 percent 
VOC destruction efficiency and upon our written approval. This 
provision will allow for owner or operators to take advantage of 
technological advances in VOC emission control for the oil and natural 
gas production industry and will provide us with valuable information 
on any new control technologies.

G. Monitoring Requirements

    Section 49.145 Monitoring Requirements requires each owner or 
operator conduct certain monitoring that we determined is necessary for 
the practical enforceability of the VOC emission reduction 
requirements, including but not limited to: (1) Monitoring of the hours 
of operation of each pit flare used to control VOC emissions in the 
event the natural gas that is being recovered for sale or other 
beneficial purpose must be diverted to an emergency control device 
because injection into the pipeline is temporarily infeasible and the 
enclosed combustor or utility flare installed at the oil and natural 
gas production facility is not operational; (2) Monitoring of the 
number of barrels of oil produced at the facility each time the oil is 
unloaded from the produced oil storage tanks; (3) Monitoring of the 
volume of natural gas from the heater-treater sent to each enclosed 
combustor, utility flare, and pit flare at all times; (4) Monitoring of 
the volume of standing, working, breathing, and flashing losses from 
the produced oil and produced water storage tanks sent to each vapor 
recovery system, enclosed combustor, utility flare, and pit flare at 
all times; (5) Directly measuring, or calculating using EPA approved 
models, various parameters (i.e., product throughput, enclosed 
combustor flame presence, temperature, etc.) related to the proper 
operation of emissions units and required control devices to assure 
compliance with the emissions reduction requirements and operational 
limitations; and (6) Visibility monitoring for detecting visible smoke 
from enclosed combustors, utility flares, and pit flares.
    These requirements are derived from the Bakken Pool Guidance in 
conjunction with NSPS OOOO. The monitoring, recordkeeping and reporting 
requirements for the covers, close-vent systems, pit flares, enclosed 
combustors, and utility flares are based, in part, on the requirements 
in the Bakken Pool Guidance. Specifically, our review and determination 
that these requirements are appropriate, as well as the Bakken Pool 
Guidance provides the basis for monitoring the flares and enclosed 
combustors. The monitoring of the covers and closed-vent systems, in 
addition to the recordkeeping and reporting requirements are based on 
the NSPS OOOO requirements for these units and are intended to provide 
legal and practical enforceability.

H. Recordkeeping Requirements

    Section 49.146 Record Keeping Requirements requires that each owner 
or operator of an oil and natural gas production facility keep specific 
records to be made available upon our request, in lieu of voluminous 
reporting requirements. The records that must be kept include, but are 
not limited to, all required measurements, monitoring, and deviations 
or exceedances of rule requirements and corrective actions taken, as 
well as any manufacturer specifications and guarantees or engineering 
analyses. These record keeping requirements were derived independently 
of the North Dakota Rules and Bakken Pool Guidance and provide legal 
and practical enforceability to the control and emission reduction 
requirements of this rule.

I. Reporting Requirements

    Section 49.147 Reporting Requirements requires that each owner or 
operator of an oil and natural gas production facility prepare and 
submit an annual report, beginning one year after this rule becomes 
effective covering the period for the previous calendar year. The 
report must include a summary of required records identifying each oil 
and natural gas production well completion or recompletion operation 
for each facility conducted during the reporting period, an 
identification of the first date of production for each oil and natural 
gas production well at each facility that commenced operation during 
the reporting period, and a summary of deviations or exceedances of any 
requirements of the FIP and the corrective measures taken. 
Additionally,

[[Page 48891]]

a report must be submitted for any performance test we require.
    We decided not to require owners or operators to register their oil 
and natural gas production facilities, because the Federal Tribal NSR 
Rule at 40 CFR 49.151 already requires registration of existing minor 
sources and such a requirement in this rule would be redundant.
    These reporting requirements were derived independently of the 
North Dakota Rules and Bakken Pool Guidance and provide legal and 
practical enforceability to the control and emission reduction 
requirements of this rule.

VII. Statutory and Executive Order

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 13563: Improving Regulation and Regulatory Review

    This action is not a ``significant regulatory action'' under the 
terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is 
therefore not subject to review under Executive Orders 12866 and 13563 
(76 FR 3821, January 21, 2011).

B. Paperwork Reduction Act

    This action does not impose an information collection burden under 
the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. 
Burden is defined at 5 CFR 1320.3(b).

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute unless the agency certifies that the 
rule will not have a significant economic impact on a substantial 
number of small entities. Small entities include small businesses, 
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of today's rule on small 
entities, small entity is defined as: (1) A small business as defined 
by the Small Business Administration's (SBA) regulations at 13 CFR 
121.201; (2) a small governmental jurisdiction that is a government of 
a city, county, town, school district or special district with a 
population of less than 50,000; and (3) a small organization that is 
any not-for-profit enterprise which is independently owned and operated 
and is not dominant in its field.
    After considering the economic impacts of today's final rule on 
small entities, I certify that this action will not have a significant 
economic impact on a substantial number of small entities. In 
determining whether a rule has a significant economic impact on a 
substantial number of small entities, the impact of concern is any 
significant adverse economic impact on small entities, since the 
primary purpose of the regulatory flexibility analyses is to identify 
and address regulatory alternatives ``which minimize any significant 
economic impact of the rule on small entities.'' 5 U.S.C. 603 and 604. 
Thus, an agency may certify that a rule will not have a significant 
economic impact on a substantial number of small entities if the rule 
relieves regulatory burden, or otherwise has a positive economic effect 
on all of the small entities subject to the rule.
    This rule will not have a significant economic impact on a 
substantial number of small entities due to the reduced regulatory 
requirement, and thus the regulatory burden, to obtain Federal CAA 
permits that this rule provides. We continue to be interested in the 
potential impacts of this rule on small entities and welcome comments 
on issues related to such impacts.

D. Unfunded Mandates Reform Act (UMRA)

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public 
Law 104-4, establishes requirements for federal agencies to assess the 
effects of their regulatory actions on State, local, and Tribal 
governments and the private sector. Under section 202 of UMRA, EPA 
generally must prepare a written statement, including a cost-benefit 
analysis, for proposed and final rules with ``Federal mandates'' that 
may result in expenditures to State, local, and Tribal governments, in 
the aggregate, or to the private sector, of $100 million or more 
(adjusted for inflation) in any one year. Before promulgating an EPA 
rule for which a written statement is needed, Section 205 of UMRA 
generally requires us to identify and consider a reasonable number of 
regulatory alternatives and adopt the least costly, most cost-
effective, or least burdensome alternative that achieves the objectives 
of the rule. The provisions of Section 205 of UMRA do not apply when 
they are inconsistent with applicable law. Moreover, Section 205 of 
UMRA allows us to adopt an alternative other than the least costly, 
most cost-effective, or least burdensome alternative if the 
Administrator publishes with the final rule an explanation why that 
alternative was not adopted. Before we establish any regulatory 
requirements that may significantly or uniquely affect small 
governments, including Tribal governments, it must have developed under 
Section 203 of UMRA a small government agency plan. The plan must 
provide for notifying potentially affected small governments, enabling 
officials of affected small governments to have meaningful and timely 
input in the development of EPA regulatory proposals with significant 
federal intergovernmental mandates, and informing, educating, and 
advising small governments on compliance with the regulatory 
requirements.
    Under Title II of UMRA, we determined that this rule does not 
contain a federal mandate that may result in expenditures that exceed 
the inflation-adjusted UMRA threshold of $100 million by State, local, 
or Tribal governments or the private sector in any one year. In 
addition, this rule does not contain a significant federal 
intergovernmental mandate as described by section 203 of UMRA nor does 
it contain any regulatory requirements that might significantly or 
uniquely affect small governments.

E. Executive Order 13132: Federalism

    Federalism (64 FR 43255, August 10, 1999) revokes and replaces 
Executive Orders 12612 (Federalism) and 12875 (Enhancing the 
Intergovernmental Partnership). Executive Order 13132 requires EPA to 
develop an accountable process to ensure ``meaningful and timely input 
by State and local officials in the development of regulatory policies 
that have federalism implications.'' ``Policies that have federalism 
implications'' is defined in the Executive Order to include regulations 
that have ``substantial direct effects on the States, on the 
relationship between the national government and the States, or on the 
distribution of power and responsibilities among the various levels of 
government.'' Under Executive Order 13132, we may not issue a 
regulation that has federalism implications, that imposes substantial 
direct compliance costs, and that is not required by statute, unless 
the federal government provides the funds necessary to pay the direct 
compliance costs incurred by State and local governments, or we consult 
with State and local officials early in the process of developing 
regulations. We also may not issue a regulation that has federalism 
implications and that preempts State law unless the Agency consults 
with State and local officials early in the process of developing 
regulations.
    This rule will not have substantial direct effects on the States, 
on the

[[Page 48892]]

relationship between the national government and the States, or on the 
distribution of power and responsibilities among the various levels of 
government, as specified in Executive Order 13132, because it regulates 
under the CAA certain stationary sources in Indian country that are not 
subject to approved CAA programs of the State of North Dakota. Thus, 
Executive Order 13132 does not apply to this action. In the spirit of 
Executive Order 13132, and consistent with EPA policy to promote 
communications between us and State and local governments, we 
specifically solicit comment on this rule from State and local 
officials.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    Executive Order 13175, entitled ``Consultation and Coordination 
with Indian Tribal Governments'' (65 FR 67249, November 6, 2000), 
requires us to develop an accountable process to ensure ``meaningful 
and timely input by Tribal officials in the development of regulatory 
policies that have Tribal implications.'' ``Policies that have Tribal 
implications'' is defined in the Executive Order to include regulations 
that have ``substantial direct effects on one or more Indian Tribes, on 
the relationship between the Federal government and the Indian Tribes, 
or on the distribution of power and responsibilities between the 
Federal government and Indian Tribes.''
    Under Section 5(b) of Executive Order 13175, we may not issue a 
regulation that has Tribal implications, that imposes substantial 
direct compliance costs, and that is not required by statute, unless 
the Federal government provides the funds necessary to pay the direct 
compliance costs incurred by Tribal governments, or we consult with 
Tribal officials early in the process of developing the proposed 
regulation. Under Section 5(c) of Executive Order 13175, we may not 
issue a regulation that has Tribal implications and that preempts 
Tribal law, unless the Agency consults with Tribal officials early in 
the process of developing the proposed regulation.
    We concluded that this final rule will have tribal implications. 
However, it will neither impose substantial direct compliance costs on 
tribal governments, nor preempt tribal law. These regulations would 
affect the FBIR community by filling a gap in air quality regulations 
and thus creating a level of air quality protection not previously 
provided under the CAA. The gap-filling approach used in this rule 
would create Federal requirements similar to those that are already in 
place in areas adjacent to the Reservation covered by the proposal. 
Finally, although Tribal governments are encouraged to partner with us 
on the implementation of these regulations, they are not required to do 
so. Since this final rule will neither impose substantial direct 
compliance costs on Tribal governments, nor preempt Tribal law, the 
requirements of Sections 5(b) and 5(c) of the Executive Order do not 
apply to this rule.
    Consistent with EPA policy, the EPA consulted with Tribal officials 
and representatives of the Three Affiliated Tribes of the Mandan, 
Hidatsa and Arikara Nations early in the process of developing this 
regulation to permit them to have meaningful and timely input into its 
development.
    Tribal consultation with the Three Affiliated Tribes of the Mandan, 
Hidatsa, and Arikara Nation was first initiated on February 17, 2012 
when we mailed a letter inviting the Tribes to consult on the first 
group of synthetic minor permits being issued on the Reservation under 
the Tribal NSR Rule. Then, on March 29, 2012, EPA senior management and 
the Chairman of the Tribes along with other government officials met 
via conference call to discuss the proposed FIP to be developed for the 
FBIR. We formally invited the Tribes to consult about the FIP in a 
letter dated April 10, 2012 to Chairman Tex Hall, of the Three 
Affiliated Tribes of the Mandan, Hidatsa, and Arikara Nation Council.
    We again met with members of the Three Affiliated Tribes of the 
Mandan, Hidatsa, and Arikara Nation Council on June 13, 2012 in New 
Town to consult and receive input from the Tribes as we developed the 
FIP. In attendance from the Council were the vice Chairman and two 
council members. The Tribes' legal counsel was also in attendance. The 
purpose of the consultation was twofold: (1) Update the Tribes on EPA's 
efforts to develop the FIP so that the air quality on the FBIR is 
protected and oil and natural gas development continues; and (2) 
discuss the Tribes' preferences regarding involvement in the FIP 
process. We provided information on our plan to prepare a FIP to ensure 
air quality protection while preventing delays in oil and natural gas 
production. EPA solicited the Tribes' input on the FIP development. The 
Council members present at the consultation meeting indicated that they 
strongly desired the FIP rule to be consistent with North Dakota's 
requirements for oil and natural gas production facilities in order to 
keep a level playing field for development and continue uninterrupted 
development of a key economic resource for the Tribe. The Council 
members expressed interest in the future delegation of the FIP so that 
the Tribes can implement the rule in place of EPA. The Council members 
also expressed interest in providing the Tribes' assistance in setting 
up a public hearing for the rule.
    As noted above, the Three Affiliated Tribes of the Mandan, Hidatsa 
and Arikara Nations have indicated preliminary interest in seeking 
administrative delegation of the Tribal NSR rule to assist us with 
administration of that rule. We will continue to work with the Tribes 
if administrative delegation is something the Tribes decide to pursue.
    Information containing the consultation process is contained in the 
docket for this rule.
    For purposes of the proposed rule, EPA specifically solicits 
additional comments on the proposed action from tribal officials.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    EPA interprets E.O. 13045 (62 FR 19885, April 23, 1997) as applying 
only to those regulatory actions that concern health or safety risks, 
such that the analysis required under section 5-501 of the E.O. has the 
potential to influence the regulation. This action is not subject to 
E.O. 13045 because it implements specific standards established by 
Congress in statutes. In addition, this rule requires control and 
reduction of emissions of VOCs, which will have a beneficial effect on 
children's health by reducing air pollution.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This action is not subject to Executive Order 13211 (66 FR 28355 
(May 22, 2001)), because it is not a significant regulatory action 
under Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (``NTTAA''), Public Law 104-113, 12(d) (15 U.S.C. 272 note) 
directs us to use voluntary consensus standards in its regulatory 
activities unless to do so would be inconsistent with applicable law or 
otherwise impractical. Voluntary consensus standards are technical 
standards (e.g., materials specifications, test methods, sampling 
procedures, and business

[[Page 48893]]

practices) that are developed or adopted by voluntary consensus 
standards bodies. NTTAA directs us to provide Congress, through OMB, 
explanations when the Agency decides not to use available and 
applicable voluntary consensus standards.
    This rulemaking does not involve technical standards. Therefore, we 
are not considering the use of any voluntary consensus standards.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994), establishes 
federal executive policy on environmental justice. Its main provision 
directs federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the United States.
    We determined that this rule will not have disproportionately high 
and adverse human health or environmental effects on minority, low 
income and indigenous populations because it is in compliance with the 
National Ambient Air Quality Standards and provides environmental 
protection for all affected populations including any minority, low 
income, and indigenous populations.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996, generally 
provides that before a rule may take effect, the agency promulgating 
the rule must submit a rule report, which includes a copy of the rule, 
to each House of the Congress and to the Comptroller General of the 
United States. Section 808 allows the issuing agency to make a rule 
effective sooner than otherwise provided by the CRA if the agency makes 
a good cause finding that notice and public procedure is impracticable, 
unnecessary or contrary to the public interest. This determination must 
be supported by a brief statement. 5 U.S.C. 808(2). As stated 
previously, EPA has made such a good cause finding, including the 
reasons therefore, and the rule is effective in the CFR August 15, 
2012. This rule is effective with actual notice for purposes of 
enforcement beginning at 5 p.m. (Eastern Daylight Time) on August 3, 
2012. This action is not a ``major rule'' as defined by 5 U.S.C. 
804(2).

List of Subjects in 40 CFR Part 49

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Indians, Intergovernmental relations, Reporting 
and recordkeeping requirements.

    Dated: August 1, 2012.
Lisa P. Jackson,
Administrator.
    40 CFR part 49 is amended as follows:

PART 49--[AMENDED]

0
1. The authority citation for part 49 continues to read as follows:

    Authority:  42 U.S.C. 7401, et seq.

PART 49--INDIAN COUNTRY: AIR QUALITY PLANNING AND MANAGEMENT

Subpart C--General Federal Implementation Plan Provisions

0
2. Add Sec. Sec.  49.140 through 49.147 and an undesignated center 
heading to appear immediately before the newly added Sec.  49.140 to 
read as follows:

Federal Implementation Plan for Oil and Natural Gas Production 
Facilities, Fort Berthold Indian Reservation (Mandan, Hidatsa and 
Arikara Nations) in EPA Region 8

Sec.  49.140  Introduction.

    (a) What is the purpose of Sec. Sec.  49.140 through 49.147? 
Sections 49.140 through 49.147 establish legally and practicably 
enforceable requirements to control and reduce VOC emissions from well 
completion operations, well recompletion operations, production 
operations, and storage operations at existing, new and modified oil 
and natural gas production facilities.
    (b) Am I subject to Sec. Sec.  49.140 through 49.147? Sections 
49.140 through 49.147 apply to each owner or operator constructing or 
operating an oil and natural gas production facility producing from the 
Bakken Pool with one or more oil and natural gas wells, for any one of 
which completion or recompletion operations are/were performed on or 
after August 12, 2007, that is located on the Fort Berthold Indian 
Reservation, which is defined by the Act of March 3, 1891 (26 Statute 
1032) and which includes all lands added to the Reservation by 
Executive Order of June 17, 1892 (the ``Fort Berthold Indian 
Reservation'').
    (c) When must I comply with Sec. Sec.  49.140 through 49.147? 
Compliance with Sec. Sec.  49.140 through 49.147 is required no later 
than November 13, 2012 or upon initiation of completion or recompletion 
operations, whichever is later.

Sec.  49.141  Delegation of authority of administration to the tribes.

    (a) What is the purpose of this section? The purpose of this 
section is to establish the process by which the Regional Administrator 
may delegate to the Mandan, Hidatsa and Arikara Nations the authority 
to assist the EPA with administration of this Federal implementation 
plan (FIP). This section provides for administrative delegation and 
does not affect the eligibility criteria under 40 CFR 49.6 for 
treatment in the same manner as a State.
    (b) How does the Tribe request delegation? In order to be delegated 
authority to assist us with administration of this FIP, the authorized 
representative of the Mandan, Hidatsa and Arikara Nations must submit a 
request to the Regional Administrator that:
    (1) Identifies the specific provisions for which delegation is 
requested;
    (2) Includes a statement by the Mandan, Hidatsa and Arikara 
Nations' legal counsel (or equivalent official) that includes the 
following information:
    (i) A statement that the Mandan, Hidatsa and Arikara Nations are an 
Indian Tribe recognized by the Secretary of the Interior;
    (ii) A descriptive statement demonstrating that the Mandan, Hidatsa 
and Arikara Nations are currently carrying out substantial governmental 
duties and powers over a defined area and that meets the requirements 
of Sec.  49.7(a)(2); and
    (iii) A description of the laws of the Mandan, Hidatsa and Arikara 
Nations that provide adequate authority to carry out the aspects of the 
rule for which delegation is requested.
    (3) Demonstrates that the Mandan, Hidatsa and Arikara Nations have, 
or will have, adequate resources to carry out the aspects of the rule 
for which delegation is requested.
    (c) How is the delegation of administration accomplished? (1) A 
Delegation of Authority Agreement will set forth the terms and 
conditions of the delegation, will specify the rule and provisions that 
the Mandan, Hidatsa and Arikara Nations shall be authorized to 
implement on behalf of the EPA, and shall be entered into by the 
Regional Administrator and the Mandan, Hidatsa and Arikara Nations. The 
Agreement will become effective upon the date that both the Regional 
Administrator and the authorized representative of the Mandan, Hidatsa 
and Arikara Nations have signed the Agreement. Once the

[[Page 48894]]

delegation becomes effective, the Mandan, Hidatsa and Arikara Nations 
will be responsible, to the extent specified in the Agreement, for 
assisting us with administration of the FIP and shall act as the 
Regional Administrator as that term is used in these regulations. Any 
Delegation of Authority Agreement will clarify the circumstances in 
which the term ``Regional Administrator''' found throughout the FIP is 
to remain the EPA Regional Administrator and when it is intended to 
refer to the ``Mandan, Hidatsa and Arikara Nations,'' instead.
    (2) A Delegation of Authority Agreement may be modified, amended, 
or revoked, in part or in whole, by the Regional Administrator after 
consultation with the Mandan, Hidatsa and Arikara Nations.
    (d) How will any delegation of authority agreement be publicized? 
The Regional Administrator shall publish a notice in the Federal 
Register informing the public of any delegation of authority agreement 
with the Mandan, Hidatsa and Arikara Nations to assist us with 
administration of all or a portion of the FIP and will identify such 
delegation in the FIP. The Regional Administrator shall also publish an 
announcement of the delegation of authority agreement in local 
newspapers.

Sec.  49.142  General provisions.

    (a) Definitions. As used in Sec. Sec.  49.140 through 49.147, all 
terms not defined herein shall have the meaning given them in the Act, 
in subpart A and subpart OOOO of 40 CFR part 60, in the Prevention of 
Significant Deterioration regulations at 40 CFR 52.21, or in the 
Federal Minor New Source Review Program in Indian Country at 40 CFR 
49.151. The following terms shall have the specific meanings given 
them.
    (1) Bakken Pool means Oil produced from the Bakken, Three Forks, 
and Sanish Formations.
    (2) Breathing losses means natural gas emissions from fixed roof 
tanks resulting from evaporative losses during storage.
    (3) Casinghead natural gas means the associated natural gas that 
naturally dissolves out of reservoir fluids during well completion 
operations and recompletion operations due to the pressure relief that 
occurs as the reservoir fluids travel up the well casinghead.
    (4) Closed vent system means a system that is not open to the 
atmosphere and that is composed of hard-piping, ductwork, connections, 
and, if necessary, flow-inducing devices that transport natural gas 
from a piece or pieces of equipment to a control device or back to a 
process.
    (5) Enclosed combustor means a thermal oxidation system with an 
enclosed combustion chamber that maintains a limited constant 
temperature by controlling fuel and combustion air.
    (6) Existing facility means an oil and natural gas production 
facility that begins actual construction prior to the effective date of 
the ``Federal Implementation Plan for Oil and Natural Gas Production 
Facilities, Fort Berthold Indian Reservation (Mandan, Hidatsa and 
Arikara Nations)''.
    (7) Flashing losses means natural gas emissions resulting from the 
presence of dissolved natural gas in the produced oil and the produced 
water, both of which are under high pressure, that occurs as the 
produced oil and produced water is transferred to storage tanks or 
other vessels that are at atmospheric pressure.
    (8) Modified facility means a facility which has undergone the 
addition, completion, or recompletion of one or more oil and natural 
gas wells, and/or the addition of any associated equipment necessary 
for production and storage operations at an existing facility.
    (9) New facility means an oil and natural gas production facility 
that begins actual construction after the effective date of the 
``Federal Implementation Plan for Oil and Natural Gas Production 
Facilities, Fort Berthold Indian Reservation (Mandan, Hidatsa and 
Arikara Nations)''.
    (10) Oil means hydrocarbon liquids.
    (11) Oil and natural gas production facility means all of the air 
pollution emitting units and activities located on or integrally 
connected to one or more oil and natural gas wells that are necessary 
for production operations and storage operations.
    (12) Oil and natural gas well means a single well that extracts 
subsurface reservoir fluids containing a mixture of oil, natural gas, 
and water.
    (13) Owner or operator means any person who owns, leases, operates, 
controls, or supervises an oil and natural gas production facility.
    (14) Permit to construct or construction permit means a permit 
issued by the Regional Administrator pursuant to 40 CFR 49.151, 52.10 
or 52.21, or a permit issued by a Tribe pursuant to a program approved 
by the Administrator under 40 CFR part 51, subpart I, authorizing the 
construction or modification of a stationary source.
    (15) Permit to operate or operating permit means a permit issued by 
the Regional Administrator pursuant to 40 CFR part 71, or by a Tribe 
pursuant to a program approved by the Administrator under 40 CFR part 
51 or 40 CFR part 70, authorizing the operation of a stationary source.
    (16) Pit flare means an ignition device, installed horizontally or 
vertically and used in oil and natural gas production operations to 
combust produced natural gas and natural gas emissions.
    (17) Produced natural gas means natural gas that is separated from 
extracted reservoir fluids during production operations.
    (18) Produced oil means oil that is separated from extracted 
reservoir fluids during production operations.
    (19) Produced oil storage tank means a unit that is constructed 
primarily of non-earthen materials (such as steel, fiberglass, or 
plastic) which provides structural support and is designed to contain 
an accumulation of produced oil.
    (20) Produced water means water that is separated from extracted 
reservoir fluids during production operations.
    (21) Produced water storage tank means a unit that is constructed 
primarily of non-earthen materials (such as steel, fiberglass, or 
plastic) which provides structural support and is designed to contain 
an accumulation of produced water.
    (22) Production operations means the extraction and separation of 
reservoir fluids from an oil and natural gas well, using separators and 
heater-treater systems. A separator is a pressurized vessel designed to 
separate reservoir fluids into their constituent components of oil, 
natural gas and water. A heater-treater is a unit that heats the 
reservoir fluid to break oil/water emulsions and to reduce the oil 
viscosity. The water is then typically removed by using gravity to 
allow the water to separate from the oil.
    (23) Regional Administrator means the Regional Administrator of EPA 
Region 8 or an authorized representative of the Regional Administrator.
    (24) Standing losses means natural gas emissions from fixed roof 
tanks as a result of evaporative losses during storage.
    (25) Storage operations means the transfer of produced oil and 
produced water to storage tanks, the filling of the storage tanks, the 
storage of the produced oil and produced water in the storage tanks, 
and the draining of the produced oil and produced water from the 
storage tanks.
    (26) Supervisory Control and Data Acquisition (SCADA) system 
generally refers to industrial control computer systems that monitor 
and control

[[Page 48895]]

industrial infrastructure or facility-based processes.
    (27) Utility flare means thermal oxidation system using an open 
(without enclosure) flame. An enclosed combustor as defined in 
Sec. Sec.  49.140 through 49.147 is not considered a flare.
    (28) Visible Smoke emissions means a pollutant generated by thermal 
oxidation in a flare or enclosed combustor and occurring immediately 
downstream of the flame. Visible smoke occurring within, but not 
downstream of, the flame, is not considered to constitute visible smoke 
emissions.
    (29) Well completion means the process that allows for the flowback 
of oil and natural gas from newly drilled wells to expel drilling and 
reservoir fluids and tests the reservoir flow characteristics, which 
may vent produced hydrocarbons to the atmosphere via an open pit or 
tank.
    (30) Well completion operation means any oil and natural gas well 
completion using hydraulic fracturing occurring at an oil and natural 
gas production facility.
    (31) Well recompletion operation means any oil and natural gas well 
completion using hydraulic refracturing occurring at an oil and natural 
gas production facility.
    (32) Working losses means natural gas emissions from fixed roof 
tanks resulting from evaporative losses during filling and emptying 
operations.
    (b) Requirement for testing. The Regional Administrator may require 
that an owner or operator of an oil and natural gas production facility 
demonstrate compliance with the requirements of the ``Federal 
Implementation Plan for Oil and Natural Gas Production Facilities, Fort 
Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nations)'' by 
performing a source test and submitting the test results to the 
Regional Administrator. Nothing in the ``Federal Implementation Plan 
for Oil and Natural Gas Production Facilities, Fort Berthold Indian 
Reservation (Mandan, Hidatsa and Arikara Nations)'' limits the 
authority of the Regional Administrator to require, in an information 
request pursuant to section 114 of the Act, an owner or operator of an 
oil and natural gas production facility subject to the ``Federal 
Implementation Plan for Oil and Natural Gas Production Facilities, Fort 
Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nations)'' to 
demonstrate compliance by performing testing, even where the facility 
does not have a permit to construct or a permit to operate.
    (c) Requirement for monitoring, recordkeeping, and reporting. 
Nothing in ``Federal Implementation Plan for Oil and Natural Gas 
Production Facilities, Fort Berthold Indian Reservation (Mandan, 
Hidatsa and Arikara Nations)'' precludes the Regional Administrator 
from requiring monitoring, recordkeeping and reporting, including 
monitoring, recordkeeping and reporting in addition to that already 
required by an applicable requirement, in a permit to construct or 
permit to operate in order to ensure compliance.
    (d) Credible evidence. For the purposes of submitting reports or 
establishing whether or not an owner or operator of an oil and natural 
gas production facility has violated or is in violation of any 
requirement, nothing in the ``Federal Implementation Plan for Oil and 
Natural Gas Production Facilities, Fort Berthold Indian Reservation 
(Mandan, Hidatsa and Arikara Nations)'' shall preclude the use, 
including the exclusive use, of any credible evidence or information, 
relevant to whether a facility would have been in compliance with 
applicable requirements if the appropriate performance or compliance 
test had been performed.

Sec.  49.143  Construction and operational control measures.

    (a) Each owner or operator must operate and maintain all liquid and 
gas collection, storage, processing and handling operations, regardless 
of size, so as to minimize leakage of natural gas emissions to the 
atmosphere.
    (b) During all oil and natural gas well completion operations or 
recompletion operations at an oil and natural gas production facility 
and prior to the first date of production of each oil and natural gas 
well, each owner or operator must, at a minimum, route all casinghead 
natural gas to a utility flare or a pit flare capable of reducing the 
mass content of VOC in the natural gas emissions vented to it by at 
least 90.0 percent or greater and operated as specified in Sec.  49.144 
and Sec.  49.145.
    (c) Beginning with the first date of production from any one oil 
and natural gas well at an oil and natural gas production facility, 
each owner or operator must, at a minimum, route all natural gas 
emissions from production operations and storage operations to a 
control device capable of reducing the mass content of VOC in the 
natural gas emissions vented to it by at least 90.0 percent or greater 
and operated as specified in Sec.  49.144 and Sec.  49.145.
    (d) Within ninety (90) days of the first date of production from 
any oil and natural gas well at an oil and natural gas production 
facility, each owner or operator must:
    (1) Route the produced natural gas from the production operations 
through a closed-vent system to:
    (i) An operating system designed to recover and inject all the 
produced natural gas into a natural gas gathering pipeline system for 
sale or other beneficial purpose; or
    (ii) A utility flare or equivalent combustion device capable of 
reducing the mass content of VOC in the produced natural gas vented to 
the device by at least 98.0 percent or greater and operated as 
specified in Sec.  49.144 and Sec.  49.145.
    (2) Route all standing, working, breathing, and flashing losses 
from the produced oil storage tanks and any produced water storage tank 
interconnected with the produced oil storage tanks through a closed-
vent system to:
    (i) An operating system designed to recover and inject the natural 
gas emissions into a natural gas gathering pipeline system for sale or 
other beneficial purpose; or
    (ii) An enclosed combustor or utility flare capable of reducing the 
mass content of VOC in the natural gas emissions vented to the device 
by at least 98.0 percent or greater and operated as specified in Sec.  
49.144(c) and Sec.  49.145.
    (iii) If the uncontrolled potential to emit VOCs from the aggregate 
of all produced oil storage tanks and produced water storage tanks 
interconnected with produced oil storage tanks at an oil and natural 
gas production facility is less than, and reasonably expected to remain 
below, 20 tons in any consecutive 12-month period, then, upon written 
approval by the EPA the owner or operator may use a pit flare, an 
enclosed combustor or a utility flare that is capable of reducing the 
mass content of VOC in the natural gas emissions from the storage tanks 
vented to the device by only 90.0 percent.
    (e) In the event that pipeline injection of all or part of the 
natural gas collected in an operating system designed to recover and 
inject natural gas becomes temporarily infeasible and there is no 
operational enclosed combustor or utility flare at the facility, the 
owner or operator must route the natural gas that cannot be injected 
through a closed-vent system to a pit flare operated as specified in 
Sec.  49.144 and Sec.  49.145.
    (f) Produced oil storage tanks and any produced water storage tanks 
interconnected with produced oil storage tanks subject to and 
controlled under the requirements specified in 40 CFR part 60, subpart 
OOOO are considered to meet the requirements of

[[Page 48896]]

Sec.  49.143(d)(2). No further requirements apply for such storage 
tanks under Sec.  49.143(d)(2).

Sec.  49.144  Control equipment requirements.

    (a) Covers. Each owner or operator must equip all openings on each 
produced oil storage tank and produced water storage tank 
interconnected with produced oil storage tanks with a cover to ensure 
that all natural gas emissions are efficiently being routed through a 
closed-vent system to a vapor recovery system, an enclosed combustor, a 
utility flare, or a pit flare.
    (1) Each cover and all openings on the cover (e.g., access hatches, 
sampling ports, pressure relief valves (PRV), and gauge wells) shall 
form a continuous impermeable barrier over the entire surface area of 
the produced oil and produced water in the storage tank.
    (2) Each cover opening shall be secured in a closed, sealed 
position (e.g., covered by a gasketed lid or cap) whenever material is 
in the unit on which the cover is installed except during those times 
when it is necessary to use an opening as follows:
    (i) To add material to, or remove material from the unit (this 
includes openings necessary to equalize or balance the internal 
pressure of the unit following changes in the level of the material in 
the unit);
    (ii) To inspect or sample the material in the unit; or
    (iii) To inspect, maintain, repair, or replace equipment located 
inside the unit.
    (3) Each thief hatch cover shall be weighted and properly seated.
    (4) Each PRV shall be set to release at a pressure that will ensure 
that natural gas emissions are routed through the closed-vent system to 
the vapor recovery system, the enclosed combustor, or the utility flare 
under normal operating conditions.
    (b) Closed-vent systems. Each owner or operator must meet the 
following requirements for closed-vent systems:
    (1) Each closed-vent system must route all produced natural gas and 
natural gas emissions from production and storage operations to the 
natural gas sales pipeline or the control devices required by paragraph 
(a) of this section.
    (2) All vent lines, connections, fittings, valves, relief valves, 
or any other appurtenance employed to contain and collect natural gas, 
vapor, and fumes and transport them to a natural gas sales pipeline and 
any VOC control equipment must be maintained and operated properly at 
all times.
    (3) Each closed-vent system must be designed to operate with no 
detectable natural gas emissions.
    (4) If any closed-vent system contains one or more bypass devices 
that could be used to divert all or a portion of the natural gas 
emissions, from entering a natural gas sales pipeline and/or any 
control devices, the owner or operator must meet one of the following 
requirements for each bypass device:
    (i) At the inlet to the bypass device that could divert the natural 
gas emissions away from a natural gas sales pipeline or a control 
device and into the atmosphere, properly install, calibrate, maintain, 
and operate a natural gas flow indicator that is capable of taking 
continuous readings and sounding an alarm when the bypass device is 
open such that natural gas emissions are being, or could be, diverted 
away from a natural gas sales pipeline or a control device and into the 
atmosphere;
    (ii) Secure the bypass device valve installed at the inlet to the 
bypass device in the non-diverting position using a car-seal or a lock-
and-key type configuration;
    (iii) Low leg drains, high point bleeds, analyzer vents, open-ended 
valves or lines, and safety devices are not subject to the requirements 
applicable to bypass devices.
    (c) Enclosed combustors and utility flares. Each owner or operator 
must meet the following requirements for enclosed combustors and 
utility flares:
    (1) For each enclosed combustor or utility flare, the owner or 
operator must follow the manufacturer's written operating instructions, 
procedures and maintenance schedule to ensure good air pollution 
control practices for minimizing emissions;
    (2) For each enclosed combustor or utility flare, the owner or 
operator must ensure there is sufficient capacity to reduce the mass 
content of VOC in the produced natural gas and natural gas emissions 
routed to it by at least 98.0 percent for the minimum and maximum 
natural gas volumetric flow rate and BTU content routed to the device;
    (3) Each enclosed combustor or utility flare must be operated to 
reduce the mass content of VOC in the produced natural gas and natural 
gas emissions routed to it by at least 98.0 percent;
    (4) The owner or operator must ensure that each utility flare is 
designed and operated in accordance with the requirements of 40 CFR 
60.18(b) for such flares.
    (5) The owner or operator must ensure that each enclosed combustor 
is:
    (i) A model demonstrated by a manufacturer to the meet the VOC 
destruction efficiency requirements of Sec. Sec.  49.140 through 49.147 
using the procedure specified in 40 CFR part 60, subpart OOOO at Sec.  
60.5413(d) by the due date of the first annual report as specified in 
Sec.  49.147(b); or
    (ii) Demonstrated to meet the VOC destruction efficiency 
requirements of Sec. Sec.  49.140 through 49.147 using EPA approved 
performance test methods specified in 40 CFR part 60, subpart OOOO at 
Sec.  60.5413(b) by the due date of the first annual report as 
specified in Sec.  49.147(b); or
    (iii) Until such time that 40 CFR part 60, subpart OOOO is 
promulgated, demonstrated to meet the VOC destruction efficiency 
requirements of Sec. Sec.  49.140 through 49.147 by using the EPA 
approved performance test methods specified in 40 CFR part 63, subpart 
HH at Sec.  63.772(e)(1)(i) through (iii) for hazardous air pollutants, 
by the due date of the first annual report as specified in Sec.  
49.147(b).
    (6) The owner or operator must ensure that each enclosed combustor 
and utility flare is:
    (i) Operated properly at all times that natural gas is routed to 
it;
    (ii) Operated with a liquid knock-out system to collect any 
condensable vapors (to prevent liquids from going through the control 
device);
    (iii) Equipped with a flash-back flame arrestor;
    (iv) Equipped with one of the following:
    (A) A continuous burning pilot flame, a thermocouple, and a 
malfunction alarm and remote notification system if the pilot flame 
fails.
    (B) An electronically controlled auto-ignition system with a 
malfunction alarm and remote notification system if the pilot flame 
fails while produced natural gas or natural gas emissions are flowing 
to the enclosed combustor or utility flare;
    (v) Equipped with a continuous recording device, such as a chart 
recorder, data logger or similar device, or connected to a Supervisory 
Control and Data Acquisition (SCADA) system, to monitor and document 
proper operation of the enclosed combustor or utility flare;
    (vi) Maintained in a leak-free condition; and
    (vii) Operated with no visible smoke emissions.
    (d) Pit Flares. Each owner or operator must meet the following 
requirements for pit flares:
    (1) The owner or operator must develop written operating 
instructions, operating procedures and maintenance schedules to ensure 
good air pollution control practices for minimizing emissions from the 
pit flare based on the site-specific design.

[[Page 48897]]

    (2) The owner or operator must only use a pit flare for the 
following operations:
    (i) To control produced natural gas and natural gas emissions 
during well completion operations or recompletion operations;
    (ii) To control natural gas emissions in the event that natural gas 
recovered for pipeline injection must be diverted to an emergency 
control device because injection is temporarily infeasible and the 
enclosed combustor or utility flare installed at the oil and natural 
gas production facility is not operational. Use of the pit flare for 
this situation is limited to a maximum of 500 hours in any twelve (12) 
consecutive months during periods when pipeline injection has become 
temporarily infeasible and no enclosed combustor or utility flare 
installed at the facility is operational; or
    (iii) Control of standing, working, breathing, and flashing losses 
from the produced oil storage tanks and any produced water storage tank 
interconnected with the produced oil storage tanks if the uncontrolled 
potential VOC emissions from the aggregate of all produced oil storage 
tanks and produced water storage tanks interconnected with produced oil 
storage tanks is less than, and reasonably expected to remain below, 20 
tons in any consecutive 12-month period.
    (3) The owner or operator must only use the pit flare under the 
following conditions and limitations:
    (i) The pit flare is operated to reduce the mass content of VOC in 
the produced natural gas and natural gas emissions routed to it by at 
least 90.0 percent;
    (ii) The pit flare is operated in accordance with the site-specific 
written operating instructions, operating procedures, and maintenance 
schedules to ensure good air pollution control practices for minimizing 
emissions;
    (iii) The pit flare is operated with no visible smoke emissions;
    (iv) The pit flare is equipped with an electronically controlled 
auto-ignition system with a malfunction alarm and remote notification 
system if the pilot flame fails;
    (v) The pit flare is visually inspected for the presence of a pilot 
flame anytime produced natural gas or natural gas emissions are being 
routed to it. Should the pilot flame fail, the flame must be relit as 
soon as safely possible and the electronically controlled auto-ignition 
system must be repaired or replaced before the pit flare is utilized 
again; and
    (vi) The owner or operator does not deposit or cause to be 
deposited into a flare pit any oil field fluids or oil and natural gas 
wastes other than those designed to go to the pit flare.
    (e) Other Control Devices. Upon written approval by the EPA, the 
owner or operator may use control devices other than those listed above 
that are capable of reducing the mass content of VOC in the natural gas 
routed to it by at least 98.0 percent, provided that:
    (1) In operating such control devices, the owner or operator must 
follow the manufacturer's written operating instructions, procedures 
and maintenance schedule to ensure good air pollution control practices 
for minimizing emissions; and
    (2) The owner or operator must ensure there is sufficient capacity 
to reduce the mass content of VOC in the produced natural gas and 
natural gas emissions routed to such other control devices by at least 
98.0 percent for the minimum and maximum natural gas volumetric flow 
rate and BTU content routed to each device.
    (3) The owner or operator must operate such a control device to 
reduce the mass content of VOC in the produced natural gas and natural 
gas emissions routed to it by at least 98.0 percent.

Sec.  49.145  Monitoring requirements.

    (a) Each owner and operator must measure the barrels of oil 
produced at the oil and natural gas production facility each time the 
oil is unloaded from the produced oil storage tanks using the 
methodologies of tank gauging or positive displacement metering system, 
as appropriate, as established by the US Department of the Interior's 
Bureau of Land Management at 43 CFR part 3160, in the ``Onshore Oil and 
Gas Operations; Federal and Indian Oil & Gas Leases; Onshore Oil and 
Gas Order No. 4; Measurement of Oil.''
    (b) Each owner or operator must monitor the hours that each pit 
flare is operated to control natural gas emissions in the event that 
natural gas recovered for pipeline injection must be diverted to an 
emergency control device because injection is temporarily infeasible 
and the enclosed combustor or utility flare installed at the oil and 
natural gas production facility is not operational.
    (c) Each owner or operator must monitor the volume of produced 
natural gas sent to each enclosed combustor, utility flare, and pit 
flare at all times. Methods to measure the volume include, but are not 
limited to, direct measurement and gas-to-oil ratio (GOR) laboratory 
analyses.
    (d) Each owner or operator must monitor the volume of standing, 
working, breathing, and flashing losses from the produced oil and 
produced water storage tanks sent to each vapor recovery system, 
enclosed combustor, utility flare, and pit flare at all times. Methods 
to measure the volume include, but are not limited to, direct 
measurement or GOR laboratory analyses.
    (e) Each owner or operator must perform quarterly visual 
inspections of tank thief hatches, covers, seals, PRVs, and closed vent 
systems to ensure proper condition and functioning and repair any 
damaged equipment. The quarterly inspections must be performed while 
the produced oil and produced water storage tanks are being filled.
    (f) Each owner or operator must perform quarterly visual 
inspections of the peak pressure and vacuum values in each closed vent 
system and control system for the produced oil and produced water 
storage tanks to ensure that the pressure and vacuum relief set-points 
are not being exceeded in a way that has resulted, or may result, in 
venting and possible damage to equipment. The quarterly inspections 
must be performed while the produced oil and produced water storage 
tanks are being filled.
    (g) Each owner or operator must monitor the operation of each 
enclosed combustor, utility flare, and pit flare to confirm proper 
operation as follows:
    (1) Continuously monitor the enclosed combustor, utility flare, and 
pit flare operation, using a malfunction alarm and remote notification 
system for failures, and checking the system for proper operation 
whenever an operator is on site, at a minimum quarterly;
    (2) Continuously monitor all variable operational parameters 
specified in the written operating instructions and procedures;
    (3) Using EPA Reference Method 22 of 40 CFR part 60, Appendix A, 
confirm that no visible smoke emissions are present, except for periods 
not to exceed a total of 2 minutes during any hour, during operation of 
any enclosed combustor, utility flare, or pit flare whenever an 
operator is on site; at a minimum quarterly. The observation period 
shall be 1 hour; and
    (4) Respond to any observation of improper monitoring equipment 
operation or any pilot flame failure alarm and ensure the monitoring 
equipment is returned to proper operation and/or the pilot flame is 
relit as soon as practicable and safely possible after an observation 
or an alarm sounds.
    (h) Where sufficient to meet the monitoring and recordkeeping 
requirements in Sec.  49.145 and Sec.  49.146, the owner or operator 
may use a

[[Page 48898]]

Supervisory Control and Data Acquisition (SCADA) system to monitor and 
record the required data in Sec. Sec.  49.140 through 49.147.

Sec.  49.146  Recordkeeping requirements.

    (a) Each owner or operator must maintain the following records:
    (1) The measured barrels of oil produced at the oil and natural gas 
production facility each time the oil is unloaded from the produced oil 
storage tanks;
    (2) The volume of produced natural gas sent to each enclosed 
combustor, utility flare, and pit flare at all times;
    (3) The volume of natural gas emissions from the produced oil 
storage tanks and produced water storage tanks sent to each enclosed 
combustor, utility flare, and pit flare at all times;
    (4) For each oil and natural gas well completion operation and 
recompletion operation at an oil and natural gas production facility:
    (i) Records identifying each oil and natural gas well completion 
operation and recompletion operation for each oil and natural gas 
production facility; and
    (ii) The latitude and longitude location of the oil and natural gas 
well; the date, time, and duration of flowback from the oil and natural 
gas well; the date, time, and duration of any venting of produced 
natural gas from the oil and natural gas well; and specific reasons for 
each instance of venting in lieu of capture or combustion. The duration 
must be specified in hours.
    (5) For each enclosed combustor, utility flare, and pit flare at an 
oil and natural gas production facility:
    (i) Written, site-specific designs, operating instructions, 
operating procedures and maintenance schedules;
    (ii) Records of all required monitoring of operations;
    (iii) Records of any deviations from the operating parameters 
specified by the written site-specific designs, operating instructions, 
and operating procedures. The records must include the enclosed 
combustor, utility flare, or pit flare's total operating time during 
which a deviation occurred, the date, time and length of time that 
deviations occurred, and the corrective actions taken and any 
preventative measures adopted to operate the device within that 
operating parameter;
    (iv) Records of any instances in which the pilot flame is not 
present or the monitoring equipment is not functioning in the enclosed 
combustor, the utility flare, or the pit flare, the date and times of 
the occurrence, the corrective actions taken, and any preventative 
measures adopted to prevent recurrence of the occurrence;
    (v) Records of any instances in which a recording device installed 
to record data from the enclosed combustor, utility flare, or pit flare 
is not operational; and
    (vi) Records of any time periods in which visible smoke emissions 
are observed emanating from the enclosed combustor, utility flare, or 
pit flare.
    (6) For each pit flare at an oil and natural gas production 
facility, a demonstration of compliance with the use restrictions set 
forth in Sec.  49.144(d)(2)(ii) is made by keeping records in a log 
book, or similar recording system, during each period of time that the 
pit flare is operating. The records must contain the following 
information:
    (i) Date and time the pit flare was started up and subsequently 
shut down;
    (ii) Total hours operated when pipeline injection was temporarily 
infeasible for the current calendar month plus the previous consecutive 
eleven (11) calendar months; and
    (iii) Brief descriptions of the justification for each period of 
operation.
    (7) Records of any instances in which any closed-vent system or 
control device was bypassed or down, the reason for each incident, its 
duration, and the corrective actions taken and any preventative 
measures adopted to avoid such bypasses or downtimes; and
    (8) Documentation of all produced oil storage tank and produced 
water storage tank inspections required in Sec.  49.145(d) and (e). All 
inspection records must include, at a minimum, the following 
information:
    (i) The date of the inspection;
    (ii) The findings of the inspection;
    (iii) Any adjustments or repairs made as a result of the 
inspections, and the date of the adjustment or repair; and
    (iv) The inspector's name and signature.
    (b) Each owner or operator must keep all records required by this 
section onsite at the facility or at the location that has day-to-day 
operational control over the facility and must make the records 
available to the EPA upon request.
    (c) Each owner or operator must retain all records required by this 
section for a period of at least five (5) years from the date the 
record was created.

Sec.  49.147  Notification and reporting requirements.

    (a) Each owner or operator must submit any documents required under 
this section to: U.S. Environmental Protection Agency, Region 8 Office 
of Enforcement, Compliance & Environmental Justice, Air Toxics and 
Technical Enforcement Program, 8ENF-AT, 1595 Wynkoop Street, Denver, 
Colorado 80202. Documents may be submitted electronically to 
r8airreport@epa.gov.
    (b) Each owner and operator must submit an annual report containing 
the information specified in paragraphs (b)(1) through (4) of this 
section. The annual report must cover the period for the previous 
calendar year. The initial annual report is due 1 year after the first 
date of production for the first oil and natural gas well at each oil 
and natural gas production facility or 1 year after August 15, 2012, 
whichever is later. Subsequent annual reports are due on the same date 
each year as the initial annual report. If you own or operate more than 
one oil and natural gas production facility, you may submit one report 
for multiple oil and natural gas production facilities provided the 
report contains all of the information required as specified in 
paragraphs (b)(1) through (4) of this section. Annual reports may 
coincide with title V reports as long as all the required elements of 
the annual report are included. The EPA may approve a common schedule 
on which reports required by Sec. Sec.  49.140 through 49.147 may be 
submitted as long as the schedule does not extend the reporting period.
    (1) The company name and the address of the oil and natural gas 
production facility or facilities.
    (2) An identification of each oil and natural gas production 
facility being included in the annual report.
    (3) The beginning and ending dates of the reporting period.
    (4) For each oil and natural gas production facility, the 
information in paragraphs (b)(4)(i) through (iii) of this section.
    (i) A summary of all required records identifying each oil and 
natural gas well completion or recompletion operation for each oil and 
natural gas production facility conducted during the reporting period;
    (ii) An identification of the first date of production for each oil 
and natural gas well at each oil and natural gas production facility 
that commenced production during the reporting period; and
    (iii) A summary of cases where construction or operation was not 
performed in compliance with the requirements specified in Sec.  
49.143, Sec.  49.144, or Sec.  49.145 for each oil and natural gas well 
at each oil and natural gas production facility, and the corrective 
measures taken.

[FR Doc. 2012-19698 Filed 8-14-12; 8:45 am]
BILLING CODE 6560-50-P