48878 Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Rules and Regulations 

■ 23. Add § 721.10535 to subpart E to 

read as follows: 

§ 721.10535 Phosphonium, 

tributyltetradecyl-, chloride (1:1). 

(a) Chemical substance and significant 

new uses subject to reporting. (1) The 

chemical substance identified as 

phosphonium, tributyltetradecyl-, 

chloride (1:1) (PMN P–12–275; CAS No. 

81741–28–8) is subject to reporting 

under this section for the significant 

new uses described in paragraph (a)(2) 

of this section. 

(2) The significant new uses are: 

(i) Release to water. Requirements as 

specified in § 721.90(a)(1), (b)(1), and 

(c)(1). 

(ii) [Reserved] 

(b) Specific requirements. The 

provisions of subpart A of this part 

apply to this section except as modified 

by this paragraph. 

(1) Recordkeeping. Record keeping 

requirements as specified in 

§ 721.125(a), (b), (c), and (k) are 

applicable to manufacturers, importers, 

and processors of this substance. 

(2) Limitations or revocation of 

certain notification requirements. The 

provisions of § 721.185 apply to this 

section. 

[FR Doc. 2012–20039 Filed 8–14–12; 8:45 am] 

BILLING CODE 6560–50–P 

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. 

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-tooil 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. 


srobinson on DSK4SPTVN1PROD with RULES
Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Rules and Regulations 48879 

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. 

(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

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 timelimited. 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 


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48880 Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Rules and Regulations 

2Resolving 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. 

3The draft permits that underwent a public 

review and comment period are available online at: 

http://www.epa.gov/region8/air/permitting/ 

pubcomment.html. 

4The FBIR CAFOs are included in the docket for 

this rule. 

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 caseby-case basis using information 

submitted in each application. 

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 resourceintensive 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. 

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 


srobinson on DSK4SPTVN1PROD with RULES
Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Rules and Regulations 48881 

5North 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. 

6NDCC (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. 

7EPA Administrative Enforcement Dockets, 

available at: http://yosemite.epa.gov/oa/rhc/ 

epaadmin.nsf. 

8The Bakken Pool is defined as a compilation of 

crude oil formations consisting of Bakken, Sanish 

and Three Forks formations. 

9The 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, 

Continued 

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. 

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. 

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. 

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 


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until such time that the final rule is published in 

the Federal Register. 

10Bakken 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. 

11The information reviewed was contained in 

synthetic minor NSR applications submitted to 

EPA, which are included in the docket for this rule. 

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. 

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. 

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 preconstruction 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 pollutionemitting 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

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, 


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Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Rules and Regulations 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 


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48884 Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Rules and Regulations 

12MDEQ. 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. 

13WDEQ 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. 

14Colorado 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. 

15Utah 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. 

16Texas 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. 

17New 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. 

18Oklahoma 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]. 

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 heatertreater 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 heatertreater 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. 

Regarding state regulations and 

guidance for VOC destruction efficiency 

and monitoring of enclosed combustors 

and utility flares, the rule requirements 


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Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Rules and Regulations 48885 

19For 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 offsite. Additionally, August 12, 2007 is the earliest 

well completion date identified in the CAFOs. 

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—ReservationSpecific FIP for Oil & Natural Gas 

Production Facilities; FBIR. A more 

detailed description of the Reservation 

is provided below in Section IV. 

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 § 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 


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20 VOC and NOX are precursors to ozone. 

21The 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). 

22October 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. 

23See TSD at Section 4. Reasonably Foreseeable 

Development. 

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. 

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 heatertreater 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

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. 

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 


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24Section 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). 

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 ByLaws 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 

§ 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 

§ 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

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 


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48888 Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Rules and Regulations 

25U.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. 

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 § 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 EPAapproval 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 § 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 § 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. 

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 


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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. 27Based 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. 

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

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 § 49.144 Control Equipment 

Requirements and § 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

F. Control Equipment Requirements 

The provisions in § 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 closedvent 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, § 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 § 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 closedvent 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 nondiverting 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 


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28Owners 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. 

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. 

As North Dakota has done in the 

Bakken Pool Guidance, § 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, 


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Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Rules and Regulations 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 costeffective, 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 


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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 gapfilling 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 


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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] 

■ 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 

■ 2. Add §§ 49.140 through 49.147 and 

an undesignated center heading to 

appear immediately before the newly 

added § 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 

§ 49.140 Introduction. 

(a) What is the purpose of §§ 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 §§ 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 

§§ 49.140 through 49.147? Compliance 

with §§ 49.140 through 49.147 is 

required no later than November 13, 

2012 or upon initiation of completion or 

recompletion operations, whichever is 

later. 

§ 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 

§ 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 


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48894 Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Rules and Regulations 

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. 

§ 49.142 General provisions. 

(a) Definitions. As used in §§ 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 heatertreater 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 


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industrial infrastructure or facilitybased processes. 

(27) Utility flare means thermal 

oxidation system using an open 

(without enclosure) flame. An enclosed 

combustor as defined in §§ 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. 

§ 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 § 49.144 and § 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 § 49.144 and § 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 § 49.144 

and § 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 § 49.144(c) and 

§ 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 § 49.144 and § 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 


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48896 Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Rules and Regulations 

§ 49.143(d)(2). No further requirements 

apply for such storage tanks under 

§ 49.143(d)(2). 

§ 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 

§§ 49.140 through 49.147 using the 

procedure specified in 40 CFR part 60, 

subpart OOOO at § 60.5413(d) by the 

due date of the first annual report as 

specified in § 49.147(b); or 

(ii) Demonstrated to meet the VOC 

destruction efficiency requirements of 

§§ 49.140 through 49.147 using EPA 

approved performance test methods 

specified in 40 CFR part 60, subpart 

OOOO at § 60.5413(b) by the due date 

of the first annual report as specified in 

§ 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 

§§ 49.140 through 49.147 by using the 

EPA approved performance test 

methods specified in 40 CFR part 63, 

subpart HH at § 63.772(e)(1)(i) through 

(iii) for hazardous air pollutants, by the 

due date of the first annual report as 

specified in § 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 autoignition 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. 


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Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Rules and Regulations 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. 

§ 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 setpoints 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 § 49.145 and § 49.146, 

the owner or operator may use a 


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48898 Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Rules and Regulations 

Supervisory Control and Data 

Acquisition (SCADA) system to monitor 

and record the required data in 

§§ 49.140 through 49.147. 

§ 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 

§ 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 § 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. 

§ 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 §§ 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 § 49.143, 

§ 49.144, or § 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 


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