1 

### Technical Support Document Federal Implementation Plan for Oil and Natural Gas Well Production Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa, and Arikara Nations),

North Dakota

Docket Number: EPA-R08-OAR-2012-0479

FRL-9710-4

SAN#: 5650

I. Introduction

The Environmental Protection Agency Region 8 (EPA 1 ) proposes to promulgate a Federal Implementation Plan (FIP) under the Clean Air Act ( CAA) for existing, new, and modified oil and natural gas production facilities constructing and operating on the Fort Berthold Indian Reservation (FBIR). This FIP proposes to establish federally e nforceable requirements to control volatile organic compound (VOC) emissions from oil and natural gas p roduction activities. The FIP proposes to require owners and operators of oil and natural gas well pr oduction facilities to reduce the VOC released duri ng the production and storage of hydrocarbon reservoir fluids prior to being transferred off site for sal e or treatment. This rule will be implemented by us (or by the Mandan, Hidatsa, and Arikara Nations, if delegated Tribal authority) until replaced by an EP A-approved Tribal Implementation Plan (TIP).

This rule, when promulgated, will be an important s tep in ensuring that basic air quality protection i s in place to protect health and welfare on the FBIR and at the same time would allow continued and unhindered development of the mineral resource, whi ch provides significant economic benefits to the Tribal communities through royalties and increased job opportunities. We worked with the Three Affiliated Tribes of the Mandan, Hidatsa, and Arika ra Nations to identify the primary oil and natural gas production-related sources of air pollution emissio ns on the FBIR, and evaluate the CAA statutory authorities available to regulate those facilities. Our evaluations identified concerns with unregula ted VOC emissions from oil and natural gas production o perations.

II. Description of the Affected Equipment

During typical oil and natural gas production opera tions on the FBIR, a comingled fluid stream (containing produced oil, natural gas and water) fl ows from each drilled well to a respective vertical separator and heater/treater processing unit. In t he vertical separator and heater/treater processing unit, the fluid is heated to a desired temperature range to aid in separation of the oil, natural gas and pr oduced water. This treatment at the wellhead removes impu rities and separates the phases to best meet sales delivery specifications for oil and natural gas. T he separated produced oil and produced water then flows to respective storage tanks. Oil is temporar ily stored in these on-site storage tanks prior to being

transferred either to tanker trucks or to a lease a utomatic custody transfer (LACT) unit for conveyanc e to

1 Throughout this document, “we” “us” and “our” refe r to the EPA.2

a refining process plant. Separated water is tempo rarily stored in the on-site storage tanks prior to being loaded into tanker trucks for transport and disposa l. The produced natural gas stream from the vertical s eparator and heater/treater processing unit can be metered into a natural gas sales pipeline if the pi peline infrastructure is available. If a pipeline is not available, the FIP requires the natural gas emissio ns be directed to an enclosed combustor or utility flare for combustion with 98% destruction efficiency. Du ring the initial well completion and well pad 2
construction phase of up to 90 days, or in the even t that natural gas recovered for pipeline injection must be diverted to an emergency control device because injection is temporarily infeasible and the enclose d combustor or utility flare installed at the facilit y is not operational, the FIP allows the natural ga s emissions to be directed to a pit flare for combust ion with 90% destruction efficiency.

Working, breathing (or standing), and flashing loss es from the produced oil storage tanks, and any produced water storage tanks interconnected with th e produced oil storage tanks, are captured through a common closed-vent piping system. Working losses o ccur when vapors are displaced due to the emptying and filling of produced oil and water stor age tanks. Breathing losses are the release of nat ural gas from produced oil and water storage tanks assoc iated with daily temperature fluctuations and other equilibrium effects. Flash losses occur when a liq uid with entrained natural gases are transferred fr om a vessel with higher pressure (e.g. heater/treater) t o a vessel with lower pressure (produced oil and wa ter storage tanks). The FIP requires the natural gas e missions from the storage tanks be routed to a util ity

flare or enclosed combustor with 98% destruction ef ficiency. If the operator determines it is economically feasible to use a vapor recovery devic e capable of reducing the mass content of VOC in the natural gas by 98% to capture the produced natu ral gas for beneficial purposes, the produced natur al gas may be directed into a natural gas sales pipeli ne or facility fuel line. Additionally, the FIP al lows owners or operators to use utility flares, enclosed combustors, or pit flares that are capable of redu cing the mass content of VOCs in the storage tank natura l gas emissions by only 90.0% if the total uncontrolled potential VOC emissions from all produ ced oil storage tanks and produced water storage tanks interconnected with the produced oil storage tanks are less than 20 tons in any consecutive 12- month period.

III. Purpose of Rule

1. Regulatory Gap:

In 1987, the North Dakota Department of Health (NDD oH) promulgated rules for Control of Organic Compound Emissions and Control of Emissions from Oi l and Gas Well Production Facilities requiring combustion of produced natural gas and natural gas emissions created during oil and natural gas well completion, production and storage operations. 3 Additionally, regulations under the authority of t he

2 A well pad is an oil and natural gas production fa cility that consists of one or more wells and prod uction and storage operations

3 North Dakota Century Code (Chapter 23-25 Air Poll ution Control); Air Pollution Control Rules (Articl e 33-15) at http://www.legis.nd.gov/information/acdata/html/33- 15.html: EPA-Approved Regulations, Subpart JJ – Nor th Dakota, 40 CFR Section 52.1820 Identification of Plan, Chapter 33-15-07 Control of Organic Compound Emissions, ap proved and Chapter 33-15-20-04 Control of Emissions from Oil a nd Gas Well Production Facilities, June 26, 1992.3

North Dakota Industrial Commission (NDIC) 4 were established for similar purposes and require combustion of produced gas during oil and natural g as well drilling and completion. These enforceable requirements allow oil and natural gas production f acilities in the NDDoH’s jurisdiction to take into

account the emission reductions achieved from combu stion of the associated produced natural gas and natural gas emissions when calculating their potent ial-to-emit (PTE) to determine the applicability of permitting requirements.

This has resulted in a situation where many oil and natural gas production facilities in NDDoH jurisdiction are not required to obtain Prevention of Significant Deterioration (PSD) permits prior to construction or Title V permits after operations co mmence. In addition, rules such as the NDDoH rule

for the control of VOC emissions from oil and natur al gas production facilities provide protection of the air quality in their jurisdiction. However, outsid e of New Source Review (NSR) permitting, there are no permitting mechanisms or applicable federal regulat ions that provide similar air quality protection or allow oil and natural gas production facilities ope rating on the Fort Berthold Indian Reservation to t ake into account emission controls already in use.

One exception is that certain produced oil and wate r storage tanks at these facilities may be subject to the recently finalized New Source Performance Stand ards for Crude Oil and Natural Gas Production, Transmission, and Storage (NSPS OOOO) and revised N ational Emission Standards for Hazardous Air

Pollutants from Oil and Natural Gas Production Faci lities (MACT HH) 5 . When calculating PTE for the purposes of applicability to major source PSD and T itle V permitting requirements for oil and gas production facilities on the FBIR, owners and opera tors cannot generally account for combustion of the VOC emissions from well completion, production or s torage activities if there is no required enforceab le control, even though combustion of VOC-containing p roduced natural gas and natural gas emissions is standard practice to protect the health and safety of the operator personnel. Owners or operators mus t, therefore, calculate PTE for the purposes of determ ining applicability to federal permitting requireme nts
as if the combustion units were not installed and t he VOCs were directly vented to the atmosphere.

When calculating the PTE of VOCs from the oil and n atural gas production facilities on the FBIR and taking into consideration the factors of enforceabi lity discussed above, the owners and operators have concluded that the facility-wide PTE of VOCs for ma ny existing, new, or modified oil and natural gas production facilities exceed the major source PSD a nd/or Title V emission thresholds of 250 tpy and 100 tpy, respectively. As a result, Consent Agreem ent Final Orders (CAFOs) were finalized between us and select operators on the FBIR in late August 201 1 and amended, in some cases, between then and July 2012 to establish federally enforceable requir ements at oil and natural gas production facilities

listed in the CAFOs. These orders established cont rol 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 g as production facilities is to provide an avenue to

4 NDCC (Chapter 38-08 Control of Oil and Gas Resource s); 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 Regulatio n. Available online at: https://www.dmr.nd.gov/oilgas/rules/rulebook.pd f. Accessed July 5, 2012.

5 The requirements in NSPS OOOO and revised MACT HH h ave been finalized but not yet promulgated and can be found at http://www.epa.gov/airquality/oilandgas/actions.htm l.4

compliance with the CAA to those companies prior to the expiration of the CAFOs between August 26, 2012 and August 31, 2012. Copies of all of the CAFOs can be found in the docket for the

rule.

2. Permitting Limitations:

On August 31, 2011, a minor source preconstruction permitting program for owners and operators proposing to construct minor sources in Indian Coun try, or Federal Tribal NSR Rule 6 became effective. In addition to providing us with the authority to r egulate proposed minor sources in Indian Country, t he rule established a permitting mechanism for major s ources that wish to voluntarily limit emissions to become synthetic minor sources for purposes of avoi ding the major source permitting requirements

under the Clean Air Act 7

.

Owners and operators of new major sources of regula ted air pollutants may not commence construction until obtaining a permit under the Clean Air Act. As an alternative to the major source permitting requirements for VOC emissions, many owners and ope rators currently operating on the FBIR are opting to apply for synthetic minor NSR permits und er the Federal Tribal NSR Rule to obtain the federally enforceable requirements that would recog nize the use of the controls already being used by the industry. The Federal Tribal NSR rule provides a mechanism to obtain synthetic minor permits, a process that allows us up to one year to take a fin al action (issue or deny) on an application for a synthetic minor permits. This has caused concerns that development of oil and natural gas resources o n the FBIR could be slowed.

To date, we have received such a great volume of ap plications for oil and natural gas production facilities on the FBIR, with hundreds more anticipa ted, that the need became apparent for a federally enforceable mechanism for operators to take into ac count the emissions reductions that were actually occurring or would occur from the combustion of the associated produced gas and natural gas emissions.

3. Identification of Sources of VOC Emissions

The EPA has received more than 350 synthetic minor permit applications for proposed major oil and natural gas production facilities on the FBIR since the effective date of the Federal Tribal NSR Rule. A review of these applications showed that owners and operators are primarily producing reservoir fluids

from the Bakken and Three Forks formation on the FB IR. There is an unusually high concentration of natural gases containing VOCs being produced in con junction with crude oil production operations on the FBIR. This is due to the high volatility of th e reservoir fluids of the Bakken Pool 8 from which the operators on the FBIR are extracting the crude oil.

6 40 CFR Parts 49 and 51 Review of New Sources and Mo difications in Indian Country; 76 FR 38748 (July 1, 2011).

7 The requirement to obtain major source preconstruc tion permits under the Prevention of Significant De terioration (PSD) regulations at 40 CFR Part 52; and the requirement to obtain major source operating permits under the Title V permitting programs at 40 CFR Part 71.

8 Oil from Bakken, Three Forks, and Sanish Formation s.5

Summarized below, we reviewed information compiled by the NDDoH in development of their Bakken

Pool Oil and Gas Production Facilities Air Pollutio n Control Permitting and Compliance Guidance

, effective May 2, 2011 9 (Bakken Pool Guidance) to further evaluate VOC emi ssions from oil and natural gas production facilities on the FBIR. According t o the Bakken Pool Guidance, crude oil from the Bakken Pool typically contains a high amount of lig hter end VOC components which have the potential to produce increased volumes of flash emissions com pared to typical oil production wells. Because of this, customary correlations such as API’s E&P Tank s and Vasquez-Beggs do not work well for estimating flash vapors in the Bakken Pool, potenti ally overestimating and underestimating emissions. The NDDoH recognized the need to predict tank natur al gas emissions from Bakken Pool oil and natural gas production facilities to determine applicabilit y to air pollution control permitting programs. Th e NDDoH collaborated with owners and operators of oil and gas production operations and formed the

Bakken VOC Task Force. The Goals of the Bakken VOC Task Force were to: (1) gather direct measurement data collected by various owners/operat ors within the Bakken Pool; (2) establish an emission factor that could be used to predict tank natural gas emissions from producing Bakken Pool formation wells; (3) to evaluate available emission control technologies; and (4) to recommend the bes t
emission control for different emission scenarios.

Typically, the natural gases associated with the pr oduced oil would be captured as product and injecte d directly into a natural gas sales pipeline, thus al leviating the emission of VOCs that are in the natu ral gas. However, this is a relatively new field and w hile the natural gas sales pipelines are being developed, they are minimally available at this tim e.

We reviewed information provided in 154 of the appl ications for synthetic minor NSR permits. 10 Based on these applications, we were able to determine th at the most significant source of the VOC emissions is from the equipment that handles natural gases pr oduced along with the crude oil during well completions, phase separation of the extracted rese rvoir fluids (production), and the temporary storag e of the crude oil. Due to the high VOC content of t he produced natural gas and natural gas emissions from the Bakken Pool, uncontrolled emissions of VOC s on the FBIR may have a potentially significant impact on the environment. We determined that on a verage, the emissions from production equipment related to each individual oil and natural gas well has the PTE approximately 2,165 tons per year (tpy ) of VOC where there are no natural gas sales pipelin es for the associated natural gases and no federall y enforceable requirements to control VOC in the natu ral gas. This is what led to the influx of synthet ic minor NSR permit applications to us. Of this total , approximately 1,611 tpy of VOC results from produced natural gas emissions from the heater/trea ter and 554 tpy of VOC is emitted from the produced oil and water storage tanks.

We believe that it is appropriate to focus initiall y on the oil and natural gas production operations that have been identified as having the greatest potenti al to impact future air quality on the FBIR and in

shared airsheds of North Dakota. Based on a review of the air quality status on the FBIR, we

9 Bakken Pool Oil and Gas Production Facilities Air P ollution Control Permitting & Compliance Guidance , North Dakota Department of Health Air Quality Division, May 2, 2 011

. 10 The applications can be found in the docket for th e interim final rule, Docket ID: EPA-R08-OAR-2012-0 479, which can be accessed at: http://www.regulations.gov.6

determined that VOC emission control requirements f or well completions and production and storage operations are appropriate for this FIP.

4. Reasonably Foreseeable Development

In an effort to determine future development likely to occur on the FBIR, we evaluated the October 2, 2009 Bureau of Land Management (BLM) report titled “Reasonable Foreseeable Development Scenario for Oil and Gas Activities on Bureau managed Lands in the North Dakota Study Area”. This report was supplemented on February 25, 2011 with the document titled “Revised Activity and Surface Disturbance Projections for the Reasonable Foreseeable Developm ent Scenario for Oil and Gas Activities on Bureau Managed Lands in the North Dakota Study Area”. Bot h documents are included in the docket for this rule and are publicly available at the following we bsite: http://www.blm.gov/mt/st/en/fo/north_dakota_field/r mp/RFD.html.

The FBIR is located entirely within the North Dakot a study area that was evaluated by BLM in the reports. Therefore, it was possible to obtain the oil and natural gas development potential for proje cted pad densities and associated wells for the FBIR fro m information in the reports. Based on the project ed pad densities in the 2011 supplemental report, we d etermined the potential for oil and natural gas development on the FBIR was approximately 990 well pads during the report planning period of 2010 to 2029. Although the BLM report estimated an average well density of 1.5 wells per pad, we used a value of two wells per pad to provide a conservative esti mate of well pad density in future development. We believe the average of two wells per pad to be repr esentative of typical operations on FBIR, based on information from synthetic minor permit application s and environmental assessments conducted by the

Bureau of Indian Affairs 11 . Thus, we concluded that reasonably foreseeable d evelopment on the FBIR would consist of approximately 2,000 wells or 1,000 well pads between 2010 and 2029.

5. Development of Requirements

a. Review of Comparable State Air Agencies’ Rules or G uidance

In order to determine what level of control would e ffectively fill the regulatory and air quality prot ection gap between our CAA jurisdiction on the FBIR and th e NDDoH’s CAA jurisdiction elsewhere in North Dakota, we reviewed the regulations under the North Dakota State Implementation Plan (SIP) for Air

Pollution control 12 . We also reviewed the NDDoH Bakken Pool Guidance and NDIC regulations 13

.

11 A document containing our analysis of well pad den sities from multiple environmental assessments can be found in the docket for the interim final rule, Docket ID: EPA-R 08-OAR-2012-0479, which can be accessed at: http://www.regulations.gov.

12 North Dakota Century Code (NDCC) (Chapter 23-25 Air Pollution Control); Air Pollution Control Rules (Article 33-15) Chapter 33-15-07 Control of Organic Compound Emissi ons, and Chapter 33-15-20-04 Control of Emissions f rom Oil and Gas Well Production Facilities. North Dakota Legisl ative Branch. Available online at: http://www.legis.nd.gov/information/acdata/html/33- 15.html. Accessed May 29, 2012. Within EPA approved SIP.

13 NDCC (Chapter 38-08 Control of Oil and Gas Resourc es); 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 Regulatio n. Available online at: https://www.dmr.nd.gov/oilgas/rules/rulebook.pd f. Accessed July 5, 2012. State only rule.7

Lastly, we reviewed other state oil and natural gas production-related regulations in Region 8 for are as that are similar to North Dakota in industry, meteo rology, or air quality concerns to ensure the propo sed requirements are reasonably achievable, because the control technologies are being commonly used and regulated.

The other state air pollution control agencies’ rul es and/or guidance that we reviewed were: Montana Department of Environmental Quality (MDEQ) 14 , Wyoming Department of Environmental Quality Air Quality Division (WDEQ) 15 , Colorado Department of Public Health and Environm ent Air Pollution Control Division (CDPHE) 16 and the Utah Department of Environmental Quality ( UDEQ) 17 . We also reviewed the regulations for oil and natural gas pr oduction facilities under the Texas Administrative Code, implemented by the Railroad Commission of Tex as, Oil and Gas Division (RCT) 18 , the New Mexico Environment Department Air Quality Bureau (N MED) 19 , and the Oklahoma Department of Environmental Quality Air Quality Division (ODEQ) 20 . However, we determined that it was not

relevant to review state rules that are intended to address non-VOC pollutant emissions, nonattainment area requirements, or specific localized air qualit y concerns unless such concerns are also present on the FBIR or control equipment requirements apply to the same emission units this FIP 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 r ule.

14 Montana Department of Environmental Quality. Chapt er 8 Air Quality Subchapter 16 Emission Control Req uirements for Oil and Gas Well Facilities Operating Prior to Issu ance of a Montana Air Quality Permit. Available onl ine at: http://www.deq.mt.gov/dir/legal/chapters/CH08-16.pd f

. Accessed May 29, 2012. State only rule.

15 Wyoming Department of Environmental Quality Air Qu ality Division. Oil and Gas Production Facilities C hapter 6, Section 2 Permitting Guidance, March 2010. Availabl e online at: http://deq.state.wy.us/aqd/Oil%20and%20Gas/March%20 2010%20FINAL%20O&G%20GUIDANCE.pdf. Accessed May 29, 2012. State only guidance.

16 Colorado Department of Health and Environment Air Pollution Control Division. Air Quality Control Com mission Regulation Number 7- Control of Ozone Via Ozone Pre cursors (Emissions of Volatile Organic Compounds an d Nitrogen Oxides) 5-CCR 1001-9, Section XII – Volatile Organi c Compound Emissions from Oil and Gas Operations. A vailable online at: http://www.cdphe.state.co.us/regulations/airreg s/5CCR1001-9.pdf. Accessed May 29, 2012. State only rule.

17 Utah Administrative Code, Rule R307-327 Ozone Nona ttainment and Maintenance Areas – Petroleum Liquid Storage, and Rule R649-3 Drilling and Operating Pracices. Utah D ivision of Administrative Rules. Available online a t: http://www.rules.utah.gov/publicat/code.htm. Access ed May 29, 2012. State only rule.

18 Texas Administrative Code, Title 16 Economic Regul ation, 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/. Accesse d May 29, 2012. State only rule.

19 New Mexico Administrative Code, Title 20 Environme ntal Protection, Chapter 2 Air Quality, Part 38 Hyd rocarbon Storage

Facilities. 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.

20 Oklahoma Administrative Code, Title 252 Department of Environmental Quality, Chapter 100 Air Pollutio n Control, Subchapter 37 Control of Volatile Organic Compounds . Oklahoma Secretary of State – Office of Administr ative Rules. Available online at: http://www.sos.ok.gov/oar/onli ne/viewCode.aspx. Accessed May 29, 2012. EPA approv ed 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 includ e: 252:100-37-2, 252:100-37-17, 252:100-37-18, 252:100-37-25, and 25 2:100-37-38[Revoked].8 Table 1: Summary of VOC Limitations in Comparable State Rules or Guidance

Rule or Guidance VOC Limitations for Oil and Natural Gas Production Operations

NDDoH - ND Century Code (SIP) – Chapter 23-25 Air Pollution Control, Air Pollution Control Rules, Article 33-15, Chapter 33-15-07 Control of Organic Compounds Emissions and Chapter 33-15-

20 Control of Emissions from Oil and Gas

Well Production Facilities Except for emergency vapor blowdown or relief syste ms, VOC emissions must be burned by flares or an equally ef ficient control device before being released to the ambient air. Ea ch flare must be equipped with automatic ignition system or continuo us burning pilot. Each water separator of petroleum products must be equipped with a closed-vent system and combustion device as specified by 40 CFR 60.691 (subpart QQQ).

NMED New Mexico Administrative Code Title 20, Chapter 2, Part 38 Hydrocarbon Storage Facilities If total tank battery storage for a petroleum produ ction facility exceeds 65,000 gallons, each hydrocarbon liquid tan k must be equipped with: (1) a floating roof, consisting of an external floating roof, internal floating cover or covered floating roof, which is e quipped with a closure seal or seals maintained in good repair to close the space between the roof or cover edge and tank wall; or (2) a well-maintained vapor-recovery system consisting of a vaporgathering system capable of collecting the organic compound vapors and natural gases Discharged and a vapor-disposal system capable of c ollecting the organic vapor and natural gases so as to minimize t heir emission to the atmosphere; or (3) any other device which is at least as effective to minimize vapor or natural gas loss to the atmosphere.

CDPHE AQPD Air Quality Control Commission Regulation Number 7, Section XII – Volatile Organic Compound Emissions from Oil and Gas Operations If actual uncontrolled VOC emissions from oil and c ondensate storage tanks is predicted for the first 12 months based on data from the first 90 days after the first date of productio n are predicted to be 100 tpy or greater, control for the first 90 days a fter the first date of production after the tank was newly installed, or a fter the well was newly drilled, re-completed, re-fractured or otherw ise stimulated, using enclosed combustors that achieve 95% VOC dest ruction. Enclosed combustors must be equipped with auto-igni tor, and operated in smokeless mode by first date of product ion, and contain a surveillance system to document presence of pilot flame. Operate control equipment according to manufacturer recomme ndations and conduct weekly tank and control device inspections.9

Rule or Guidance VOC Limitations for Oil and Natural Gas Production Operations

North Dakota Industrial Commission (NDIC) – ND Century Code 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.

NDDoH - Bakken Pool Oil and Gas

Production Facilities Air Pollution Control Permitting & Compliance Guidance (pages 39-43) Control Requirements for Heater-Treater Gas Heater-treater natural gas must be routed to a natu ral gas gathering pipeline as soon as practicable in accordance with the NDIC requirements. When a pipeline is not available, he ater-treater natural gas is required to be routed to a control s ystem or device.

Control Requirements for Storage Tanks VOC and HAP emissions from all active produced wate r tanks VOC and HAP emissions shall be controlled by at least 9 0% within 60- days after the first date of production. Produced oil and water tanks must be controlled by at least 90 percent if combin ed PTE declines to < 20tpy. If combined VOC PTE > 20tpy, tank VOC and HAP emissions must be controlled by at least 98% by wei ght.

Acceptable VOC Control Systems or Devices: Pit flare or other 90% DRE or greater device, equip ped with auto ignior, at a minimum; VRU or oil stabilizer on storage tanks capable of r educing VOC and HAP emissions by at least 99% by weight; Enclosed smokeless combustion device or utility fla re designed and operated to reduce the mass content of VOC and HAP by at least 98% by weight. Must be equipped with auto ignitor or continuous burning pilot with thermocouple. Daily checks for proper operation or flame presence.

Operate all air pollution control equipment in acco rdance with manufacturer recommendations and good air pollution control practice for minimizing emissions.

MDEQ Chapter 8 Air Quality, Subchapter 16 Emission Control Requirements for Oil and Gas Production Facilities Operating Prior to Issuance of a Montana Air Quality

Permit VOC vapors greater than 500 BTU/scf from oil and na tural gas wellhead equipment must be routed to a natural gas pipeline, or, if a natural gas pipeline is not located within a 1/2 mi le of the oil and natural gas well facility, VOC vapors greater than 500 BTU/scf must be captured and routed to emissions minimizing technology or to a smokeless combustion device equipped with an e lectronic ignition device or a continuous burning pilot syste m;

VOC vapors greater than 500 BTU/scf from oil and co ndensate storage tanks with the PTE of 15 TPY or greater mus t be captured and routed to a natural gas pipeline, or if a natur al gas pipeline is not located within a 1/2 mile of the oil and natural ga s well facility, VOC vapors greater than 500 BTU/scf from storage ta nks with the PTE of 15 TPY must be captured and routed to emissi ons minimizing technology, or to a smokeless combustion device equipped with an electronic ignition device or a co ntinuous burning pilot system;10

Rule or Guidance VOC Limitations for Oil and Natural Gas Production Operations

WDEQ Oil and Gas Production Facilities, Chapter 6, Section 2 Permitting Guidance New Facilities Within 60-days of the First Date of Production (FDO P), flashing emissions containing greater than or equal to 10 TP Y VOC shall be controlled by at least 98%.

Modified Facilities Within 60-days of modification, new and existing fl ashing emissions containing greater than or equal to 10 TP Y VOC shall be controlled by at least 98%.

New and Modified Facilities

Condensate and oil tanks that are on site for use d uring emergency or upset conditions, such as spare tanks at facilit ies connected to liquids gathering systems, are not subject to the 9 8% control requirements.

The removal of flashing emissions control devices m ay be allowed upon approval after one year if VOC flashing emissi ons have declined to less than, and are reasonably expected to remain below 8

TPY. ODEQ Title 252 Chapter 100 Air Pollution Control, Subchapter 37 Control of Emission of Volatile Organic Compounds VOC vessels of 400 gallons or greater shall be equi pped with permanent submerged fill piping or a vapor recovery system.

Texas Administrative Code, Title 16 Economic Regulation, Part I Railroad Commission of Texas, Chapter 3 Oil and

Gas Division. All natural gas releases greater than 24 hours dura tion burned by

flare if safe.11

Rule or Guidance VOC Limitations for Oil and Natural Gas Production Operations

UDEQ Utah Administrative Code, Rule R649-3 Drilling and Operating Practices (- 20 Gas Flaring or Venting) Produced natural gas from oil wells may be flared o r vented only in the following amounts:

• Up to 1,800 MCF from an individual well on a monthl y basis at any time without approval.

• During the period of time allowed for conducting th e stabilized production test or other approved test, the operator may vent or flare all produced oil well na tural gas as needed for conducting the test.

• During the first calendar month immediately followi ng the time allowed for conducting the initial stabili zed production test operator may vent or flare up to 3, 000 MCF of oil well natural gas without approval.

• Unavoidable or short-term oil well natural gas vent ing or flaring may occur without approval. Upon well completion and first date of production, unavoidable or short-term gas venting or flaring is allowed wit hout approval only in the following cases:

• Anytime unless the division determines that the recovery of such vapors is warranted.

• During emergencies if shutting in or restricting production from the well would cause waste or creat e adverse impact on the well or producing reservoir.

• During periods of well purging or evaluation tests not exceeding a period of 24 hours or a maximum of 144 hours per month. Greater amounts of produced natural gas may be flar ed upon written approval.

b. Comparison of Proposed Rule Requirements to State R ules and Guidance

We drafted requirements that mirror to the greatest extent practicable the most relevant aspects of th e state rules and guidance reviewed for oil and natur al gas production facilities and determined a level of control that equalizes requirements and air quality protections across jurisdictional borders yet ensu res the enforceability required for a federal rule. Th erefore, the proposed rule focuses primarily on mirroring NDDoH requirements for oil and natural ga s production facilities. The proposed rule is not as restrictive as some of the most stringent state and local rules for the same class of sources or activ ities; likewise, it is not as lenient as some of the least stringent of the state and local rules. Nor does the proposed rule look like state or local rules becaus e it uses the federal regulatory structure and is w ritten in a “plain language” format in accordance with the Plain Writing Act of 2010 21

.

21 Plain Writing Act of 2010, Pub. L. No. 111-274, § 105, 124 Stat. 2861 (2010).12

It is important to note that this FIP is analogous to, but different from, the rules for oil and natur al gas production facilities within the jurisdiction of th e NDDoH. The rule proposed today is somewhat more stringent than North Dakota’s SIP rules for oil and natural gas production sources with regard to monitoring, recordkeeping and reporting required by the CAA. However, while this is a Federal CAA rule, it does not change the minimum criteria in 40 CFR Part 51, the CAA, or the TAR for approval of

rules in either a SIP or a TIP. 22 We encourage the Three Affiliated Tribes of the M andan, Hidatsa, and Arikara Nations to develop an individual TIP and wi ll work with the Three Affiliated Tribes of the Mandan, Hidatsa, and Arikara Nations if they seek t o replace this rule with a TIP. This regulation wi ll apply until it is replaced by Tribal regulations in an approved TIP.

c. Applicability

Applicability of this proposed rule is in Section 4 9.140 – Introduction. This rule is intended to reg ulate VOC emissions in natural gases released during the completion and recompletion of oil and natural gas wells, and the production and storage of crude oil on the FBIR. Specifically, VOC-containing produced natural gas released from the casing head of each w ell during completions and all recompletions, VOCcontaining produced natural gas released from each separator and heater-treater in the production process, and VOC-containing natural gas emissions r eleased from each produced oil and each produced water storage tank due to breathing (standing), wor king, and flashing loss emissions.

The proposed rule applies to:

(1) 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 operations are/were performed on o r after August 12, 2007, that is located on the FBIR which is defined by the Act of March 3, 18 91 (26 Statute 1032) and which includes all lands added to the Reservation by Executive Order o f June 17, 1892 (the “Fort Berthold Indian Reservation”); and

(2) Each owner or operator constructing or operating a n oil and natural gas production facility with one or more oil and natural gas wells, for any one of which recompletion operations are performed after the date of publication in the code of federal regulations or after August 3, 2012 for owners or operators that were provided actual n otice by EPA, that is located on the FBIR.

For the purposes of this rule, a well completion me ans the process that allows for the flowback of oil and natural gas from newly drilled wells in order to ex pel drilling and reservoir fluids and test the rese rvoir flow characteristics, which may vent VOC to the atm osphere via an open pit or tank. A well completion operation means any oil and natural gas well comple tion with hydraulic fracturing occurring at an oil and natural gas production facility. The completio n 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 refractu ring 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

22 EPA has used the planning requirements applicable to States as a guide in developing this FIP.13

natural gas production facility. The reason we sel ected the initiation of completions operations as t he date for defining a new facility is that owners and operators use drill rigs prior to initial completi on operations and this equipment is not considered a s tationary source. In addition, it is not certain d uring the drilling operations whether a well will be a pr oducing well. Hence it is not known whether an oil and natural gas production facility will be constru cted to support that well. The outcome of a completion operation provides the well owners and o perators information necessary to determine whether an oil and gas production facility will be constructed. Requiring compliance with this rule u pon recompletion of any one well at a facility is consi stent with NSPS OOOO. According to the final NSPS OOOO notice, a completion operation associated wit h 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 thi s rule the process of refracturing is defined as a recompletion).

In deciding the effective date and the well complet ion dates for applicability, we evaluated the purpo se of the rule, the gaps in regulations, NSPS OOOO and the requirements and stipulations of the CAFOs. The August 12, 2007, date is the earliest well comp letion date identified in the CAFOs.

d. VOC Emission Reduction Requirements

Section 49.143 – Construction and Operational Contr ol Measures would restrict VOC emissions from oil and natural gas production well completion oper ations by at least 90% at all times. We note that the well completion and recompletion control requiremen ts to use pit flares or utility flares that have th e capability to reduce the mass content of VOC in the natural gas emissions routed to them by at least 9 0.0 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 emissi on completions and recompletions 23 , which would exceed the 90.0 percent VOC emission reduction requ irement.

Section 49.143 would also restrict VOC emissions fr om phase separation of the reservoir fluids and from working, standing, breathing and flashing loss natural gas emissions from temporary on-site produced oil and water storage by at least 98.0 % a t all times within 90 days after production commences, with the exception that at least 90.0 % control is allowed in the event the natural gas tha t is being recovered for sale or other beneficial purpos e must be diverted to an emergency control device because injection into the pipeline is temporarily infeasible and the enclosed combustor or utility fl are is not operational, or if total uncontrolled potential emissions of VOC from all produced oil storage tan ks and any produced water storage tanks interconnected with produced oil storage tanks have declined to less than, and are reasonably expected to stay belo w, 20 tons in any consecutive 12-month period. We developed the provision for the last exception for consistency with the NDDoH Bakken Pool Guidance. In comparison, once promulgated, NSPS OOOO will req uire 95% VOC emission reduction from storage tanks emitting greater than or equal to 6 tpy each of VOCs. Tanks emitting less than 6 tpy VOC will no t

23 U.S. Environmental Protection Agency. Lessons Lear ned from Natural Gas STAR Partners: Reduced Emissio ns Completions for Hydraulically Fractured Natural Gas Wells. Office of Air and Radiation: Natural Gas S tar Program. Washington, DC. Available at: http://epa.gov/gasstar/documents/reduced_emissions_ completions.pdf . Accessed July 26,

2012.14

require controls. We justified the 20 tpy threshold for storage tanks in aggregate based on informatio n we contained in the synthetic minor NSR application s we received which indicates a typical oil and natural gas facility requires an average of 4 tanks per well. Therefore, the storage tanks at a one we ll facility, would need to emit less than 6 tpy VOCs e ach in order to take advantage of the provision. Consequently, each tank at a multi-well facility wo uld need to emit even less than 6 tpy in order to t ake advantage of the provision.

We determined that certain operational requirements are necessary for the practical enforceability of the

VOC emission reduction requirements. We propose work p ractice and operational requirements that include, but are not limited to:

(1) On the first date of production from any oil and na tural gas production well, at a minimum, route all produced natural gas and natural gas emissions from that well to a control device capable of at least 90.0% VOC destruction efficiency, based on the site-specific design, written operating instructions, and operating procedures of the pit f lare;

(2) Within ninety (90) days of the first date of produc tion from any oil and natural gas production well, use of a closed-vent vapor recovery system de signed to recover and route the produced natural gas from the separator and heater/treater p rocessing unit to one of the following:

i. Operating equipment designed to inject it into the pipeline system for sale or other beneficial purpose; or

ii. An enclosed combustor or utility flare with VOC emi ssion destruction efficiency of at least 98%, based on the typical manufacturer specif ications or engineering design of enclosed combustors or utility flares.

(3) Use of a closed-vent vapor recovery system and encl osed combustor or utility flare with VOC emission destruction efficiency of at least 98.0% f or natural gas emissions from each produced oil storage tank and any produced water storage tan k interconnected with the produced oil storage tanks, based on the typical manufacturer sp ecifications or engineering design of enclosed combustors or utility flares. If the actu al uncontrolled VOC emissions from the aggregate of all produced oil storage tanks and any produced water storage tanks interconnected with produced oil storage tanks at an oil and natur al 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 enclos ed combustor that is capable of reducing the mass content of VOC in the natural gas emissions ve nted to the device by only 90.0% upon written approval by us.

(4) In the event the natural gas that is being recovere d for sale or other beneficial purpose must be diverted to an emergency control device because inj ection into the pipeline is temporarily infeasible and the enclosed combustor or utility fl are installed at the oil and natural gas production facility is not operational, route all p roduced natural gas emissions from the separator and heater/treater processing unit or natural gas e missions from the produced oil storage tanks to15

a pit flare capable of at least 90.0% destruction e fficiency based on the site-specific design, written operating instructions, and operating proce dures of the pit flare.

We note that owners and operators of oil and natura l 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 NS R applications to reduce the mass content of VOC emissions routed to a pit flare by at least 90.0% b y weight. We also note that while NSPS OOOO requires 95% VOC reduction of emissions from storag e tanks emitting at least 6 tpy VOCs, owners and operators of oil and natural gas production facilit ies on the FBIR have indicated that a 98% VOC destruction efficiency in the Bakken Pool Guidance is achievable and committed in their synthetic mino r NSR applications to reduce the mass content of VOC emissions routed to the enclosed combustors or utility flares used for both produced gas and stora ge tank control of at least 98.0% by weight. The 2 0 tpy VOC storage tank total emissions threshold for allowing 90.0 % VOC emission reduction instead of

98.0% is consistent with the NDDoH’s Bakken Pool Gu idance, except that we require the operator to develop written operating instructions, operating p rocedures and maintenance schedules for any pit fl are used under this provision based on the site-specifi c design of the pit flare.

Regarding state regulations and guidance other than NDDoH, the NDIC, WDEQ, MDEQ, UDEQ and RCT also require or at least allow flaring or combu stion of casinghead natural gas, produced natural g as, and produced oil and water storage tank loss natura l gas emissions when a vapor recovery system and sales pipeline are not feasible. The NDIC requires heater-treater natural gas to be routed to a natur al gas gathering pipeline as soon as practicable. When a pipeline is not available, heater-treater natural g as is required to be routed to a control system or device . The MDEQ specifically requires injection of produced natural gas and/or storage tank natural ga s emissions into a sales pipeline if there is one w ithin 1⁄2 mile of the facility. The WDEQ requires 98% redu ction of VOC flashing emissions from all storage tanks and separation vessels.

When reviewing state regulations or guidance for pr oduced oil and water storage tanks, we focused on those that might apply to the size tanks that are t ypically constructed at oil and natural gas product ion facilities on the FBIR, primarily tanks with a stor age capacity of 500 bbl each or less (approximately 21,000 gallons). The requirements proposed for con struction and emission control of produced oil and water storage tanks are consistent with all state r egulations and guidance reviewed, although there ar e varying degrees of de minimis natural gas throughpu t, storage capacities, or annual flashing emissions below which the requirements do not apply or the co ntrol equipment may be removed. The WDEQ requires 98% VOC reduction for tanks with a PTE gre ater than 10 tpy within 60 days of the first date o f production, compared to 90 days in the proposed FIP . The WDEQ also allows control equipment removal if flashing emissions decline to and are re asonably expected to remain below 8 tpy.

e. Monitoring Requirements

We determined that certain monitoring requirements are necessary for the practical enforceability of t he VOC emission reduction requirements, including but not limited to:16

(1) Monitoring of the barrels of oil produced at the fa cility each time the oil is unloaded from the produced oil storage tanks; (2) Monitoring of the volume of produced natural gas se nt to an enclosed combustor, utility flare, or pit flare at all times; (3) Monitoring of the volume of working, breathing (or standing), and flashing natural gas emissions from the produced oil and produced water storage tanks sent to vapor recovery system, enclosed combustor, utility flare, or pit flare at all times; and (4) Directly measuring, or calculating using our approv ed models, various parameters (i.e., product throughput, enclosed combustor flame presence, temp erature, etc.) related to the proper operation of emissions units and required control d evices to assure compliance with the emissions and operational limitations. (5) Visibility monitoring for detecting visible smoke f rom enclosed combustors, utility flares, and pit

flares.

The Bakken Pool Guidance is intended to address a w ider range of pollutant emissions from oil and natural gas production facilities. The proposed FI P intends only to address VOC emissions at this tim e, which we determined are the reason many of these fa cilities exceed the major source PSD and/or Title V permitting applicability thresholds.

Regarding other state regulations and guidance revi ewed for VOC destruction efficiency and monitoring of enclosed combustors and utility flares, the prop osed FIP requirements are mostly consistent with al l that specifically address those control equipment. Although CDPHE only requires 95.0 % VOC emission reduction from produced oil or water stora ge tanks, we chose a destruction efficiency of 98.0 % in accordance with NDDoH regulations.

f. Record Keeping Requirements

We propose that the applicant keep extensive record s to be made available upon us request, in lieu of voluminous reporting requirements. The records to be kept include, but are not limited to, all requir ed measurements, monitoring, and deviations or exceeda nces of rule requirements and corrective actions taken, as well as any manufacturer specifications a nd guarantees or engineering analyses.

g. Reporting Requirements

We propose that the owner or operator of an oil and natural gas production facility subject to the FIP submit an annual report each year covering the peri od for the previous calendar year. The report must include a summary of all required records identifyi ng each oil and natural gas production well completion or recompletion operation for each facil ity conducted during the reporting period, an identification of the first date of production for each oil and natural gas production well at each fa cility that commenced operation during the reporting perio d, and a summary of deviations or exceedances of any requirements of the FIP and the corrective meas ures taken. Additionally, a report shall be submit ted for any required performance test.17

IV. Cost of the rule

We evaluated the cost impact of this rule for the c ontrol technologies required under the FIP. Copies of the synthetic minor permit applications, cost infor mation, and associated supporting documentation tha t we considered in this process are included in the d ocket for this rule.

1. Emissions Data

We evaluated data from 154 synthetic minor permit a pplications containing 533 production wells among five of the main operators on the FBIR. From the a pplications, we were able to obtain the uncontrolle d

and controlled VOC emissions for each of the 154 fa cilities. Additionally, the data was analyzed to determine average emission rates for an individual well basis. Due to the variability in the producti on rates and product composition among the operators, we believe the mean value per well is an appropriate method for obtaining annual emissions. Average VOC emissions per well were evaluated against operating scenarios to determine cost impac ts associated with the FIP.

Generally, the provisions in the FIP provide operat ors with the ability to control produced natural ga s emissions from the heater/treater during the initia l phase of production (up to 90 days) with a pit fl are capable of a 90% destruction efficiency. After 90 days, the FIP requires produced natural gas emissio ns be controlled with an enclosed combustor or utility flare capable of a 98% destruction efficiency if a pipeline is not available. Natural gas emissions f rom storage tanks shall be controlled with an enclo sed combustor or utility flare capable of 98% reduction . We applied the destruction efficiency above to t he emissions data from the applications to obtain the amount of VOCs reduced on an annual basis for a single well. Additionally, we assumed that no pipe lines were available in order to develop a worst-ca se scenario estimate of emissions from production and storage operations. We believe this is a conservative approach for cost analysis purposes be cause the costs to implement the control technologies required by the FIP may be reduced or even eliminated if pipeline infrastructure is available. Also, emission estimates are likely hig her than actual emission rates due to the decline i n production over time. Average VOC emissions in tpy for production and storage operations associated with an individual well on the FBIR are presented i n Table 2 below. 24

24 A summary of VOC emissions from application data t itled “VOC Emissions Analysis from Syn Minor Applic ation Data”

can be found in the docket for the interim final ru le, Docket ID: EPA-R08-OAR-2012-0479, which can be accessed at: http://www.regulations.gov.18 Table 2- Average VOC Emissions for Single Well Parameter (per individual well) Average VOC Emissions (tpy ) Produced natural gas (heater/treater) uncontrolled VOC emissions 1,610 Storage tank uncontrolled VOC natural gas emissions 555
Total uncontrolled VOC emissions 2,165 Produced natural gas (heater/treater) controlled V OC emissions 1 65 Storage tank controlled VOC natural gas emissions 1 0

Total controlled VOC emissions 75

Total amount of reduction in VOC emissions due to c ontrols 2,090

1. Controlled produced natural gas heater/treater emi ssions calculated from 90% destruction efficiency f or 90 days and 98% destruction efficiency for the remaining 9 mont hs of the year.

2. Costs of Compliance

We relied on cost estimates supplied by oil and nat ural gas operators on the FBIR for capital costs an d annual costs associated with control technology pro visions in the FIP. 25 For each operator, the annualized capital cost was calculated by multiplyi ng the total capital investment cost by the appropr iate capital recovery factor (CRF) for the equipment lif e indicated by the operator. 26, 27 In most cases, the equipment life for control devices was 10 years and had a CRF of 0.014238 based on a 7% interest rate. Because the equipment life for pit flares varied am ong operators, the appropriate CRF based on a 7% interest rate was used to determine the capital rec overy costs. The annualized capital cost was then combined with the annual operating costs provided b y the operator to obtain the total annual cost (TAC ) for each piece of equipment. The average TAC was c alculated for each type of equipment to provide a representative annual cost for the cost analysis. 28 Equipment of concern in the cost analysis were pi t flares, single-tip utility flares, dual-tip or tand em utility flares, enclosed combustors, auto-igniti on systems, and continuous pilot systems.

Due to variability in oil and natural gas operation s on the FBIR among the production companies, we developed typical operating scenarios to evaluate t he cost impacts associated with the FIP. We believ e the scenarios analyzed are a conservative represent ation of realistic operations, based on input from the operators and knowledge of industry practice. Each scenario assumes that pipeline infrastructure is n ot available at the oil and natural gas production fac ility, or well pad, thereby requiring the combustio n of waste natural gas from various emission sources. A lthough pipeline infrastructure does exist in areas of the FBIR, this assumption provides a worst-case cos t impact analysis. Actual cost impacts of the FIP

25 The cost estimates can be found in the docket for the interim final rule, Docket ID: EPA-R08-OAR-2012 -0479, which can be accessed at: http://www.regulations.gov.

26 EPA’s Control Cost Manual at page 2-41 (further re ferred to as CCM) Sixth Edition, January 2002, EPA 452/B-02-001. The CCM can be found at http://www.epa.gov/ttncatc1 /dir1/c_allchs.pdf.

27 Capital Recovery was determined by multiplying the Total Capital Investment by the CRF for a 7% inter est rate based on the equipment life of the operator, as determined b y Table A-2 in Appendix A to Chapter 2 of the CCM. The justification for using the CRF at a 7% interest rate can be found in Office of Management and Budget, Circular A-4, Reg ulatory Analysis, http://www.whitehouse.gov/omb/circulars_a004_a-4/.

28 The cost data analysis can be found in the docket for the interim final rule, Docket ID: EPA-R08-OAR- 2012-0479, which can be accessed at: http://www.regulations.gov.19

are expected to decrease over time as the pipeline infrastructure is further developed on the FBIR. T he following operating scenarios were developed for th e cost impact analysis:

• Scenario A: A facility with one well requiring the use of a pit flare, single-tip utility flare, enclosed combustor, and two auto-ignition or contin uous pilot system devices;

• Scenario B: A facility with two or more wells requ iring the use of a pit flare, single-tip utility flare, two enclosed combustors, and three auto-igni tion or continuous pilot system devices; or

• Scenario C: A facility with more than two wells r equiring the use of a pit flare, dual-tip or tandem utility flare, and an auto-ignition or conti nuous pilot system.

The average TAC for each operating scenario is pres ented below in Table 3. All costs are presented in

2012 dollars.

Table 3 – Total Annual Cost for Operating Scenarios on the FBIR

Operating Scenario Total Annual Cost 1

Scenario A $35,750

Scenario B $52,095

Scenario C $59,975

1. Total annual cost includes the calculated capital recovery based on the equipment life and 7% interes t rate and annual operating costs provided by the operator.

As indicated in Table 3, the TAC is higher for oper ating scenarios that utilize multiple combustors or tandem utility flares. However, if the TAC is calc ulated on a per well basis, the TAC per well for operating Scenario B and C are lower than the TAC f or operating Scenario A. Input from operators on the FBIR has indicated that as the volume of produc ed natural gas and natural gas emissions increases at facilities due to higher production volumes from mo re wells at the well pad, multiple enclosed combustors or tandem utility flares are utilized to reduce operating costs. We conservatively assumed that an enclosed combustor can only process the nat ural gas emissions from a single well for destructi on. Therefore, a two-well facility would require a mini mum of two enclosed combustors. From the costs provided by the operators and the TAC for each oper ating scenario, we determined that it is typically more economical to use tandem utility flares at wel l pads consisting of three or more wells, although many factors may influence control device selection . Possible influences on control device selection may include the volume of produced natural gas and natural gas emissions at the facility, grouped installation and operating costs among multiple fac ilities, vendor pricing, safety and compliance regulations, or standardized operator preferences. By using this approach, we determined that the maximum TAC impact per well is approximately $35,75 0. However, the actual average TAC per well is likely much lower due to advances in horizontal drilling techniques resulting in multiple wells per well pad. Since we have determined future developm ent will average a well pad density of two wells per pad (Scenario B), the anticipated maximum TAC p er well is reduced to approximately $26,000.

We further evaluated the cost impact of the FIP by determining the cost effectiveness for each operati ng scenario. Using an average VOC reduction of 2,090 tpy per well, the cost effectiveness for each operating scenario is presented in Table 4.20 Table 4 – Cost Effectiveness Per Well for Operating Scenarios

Operating Scenario Emissions Reduction (tpy) Remaining

Controlled Emissions (tpy) Cost Effectiveness

($/ton VOC reduced)

Scenario A 1 2,090 75 $17

Scenario B 2 4,180 150 $12

Scenario C 3 6,270 225 $10

1. Values shown are for a single-well based on one-wel l facility

2. Values shown are for a single-well based on a two-w ell facility.

3. Values shown are for a single-well based on a three -well facility. Facilities with greater than three wells will

increase cost effectiveness.

As indicated in Table 4, the cost effectiveness for a typical two-well facility is less than $15 per t on of VOC reduced per well. As the number of wells per w ell pad increases, the cost effectiveness generally

increases.

It is also important to note that we believe the FI P does not impose any significant cost on operators that would not already be incurred in the absence of the FIP. Safety considerations and standard industry practice already require the use of control equipme nt to eliminate the explosion hazard at the well pa d, thereby reducing any danger to operator personnel a nd facility equipment. Additionally, operator environmental stewardship imposes control requireme nts to reduce potential impacts to the surrounding public and environment. Therefore, the FIP does no t impose any significant additional costs that are not already being incurred by the operators.

We would also like to note that pipeline infrastruc ture on the FBIR is anticipated to increase over th e next several years. As pipeline infrastructure bec omes available, the FIP requires operators to captu re produced natural gas and natural gas emissions when economically feasible as opposed to routing the emissions to a combustion device. Pipeline infrast ructure will not only allow operators to remove control equipment that are no longer required, but it will also generate increased revenue from the capture salable product. Furthermore, the FIP will provide the option for operators to utilize vapor recovery units (VRUs) as opposed to enclosed combus tors as a method for reducing emissions from storage tanks. As the price and demand of natural gas increases in future years, VRUs may prove to be an economic method of generating increased revenue and reducing the cost impacts of control equipment.

Using a maximum TAC impact for a two-well facility of approximately $52,000 and reasonable foreseeable development estimated at 1,000 faciliti es, the maximum annual cost of compliance with the FIP on the oil and natural gas industry is estimate d to be approximately $50 million. However, we

believe this is a conservative estimate and that ac tual annual cost would be much lower due to factors such as increased well pad density, standard indust ry practice, and anticipated pipeline infrastructur e development. Therefore, the FIP will not have an a nnual effect on the economy of $100 million or more and does not meet the definition of a significant r egulatory action under Executive Order 12866.21

V. Air Quality

The State of North Dakota operates three ambient mo nitoring sites in the western part of the state tha t are designed to characterize regional background co ncentrations of criteria pollutants. These sites a re located at Dunn Center, Theodore Roosevelt National Park-Northern Unit (TNRP) and Lostwood National Wildlife Refuge (LNWR). The sites collect background concentrations of criteria pollutants, including ozone and nitrogen dioxide (NO 2 ). The locations of monitoring sites in North Dako ta are shown below in Figure 1. The measured ambient ozon e and NO 2 concentrations in western North Dakota and the region of the FBIR are substantially lower than our National Ambient Air Quality Standard (NAAQS) of 75 parts per billion (ppb) for 8-hour average ozone and 100 ppb for 1-hour average NO 2

.

Figure 1. Locations of ambient air quality monitor ing sites in ND.

As part of the technical analysis for the FIP, we e valuated the impacts of changes in VOC and nitrogen oxide (NOx) emissions from enclosed combustors and utility flares used for the control of VOC emissions at well pads consisting of two wells on t he FBIR. The primary air pollutants that are affec ted by the FIP include VOC and NO X , where both VOC and NO X are precursors to ozone, and NO X is a precursor to NO 2 . A more detailed discussion of our evaluation on the ozone and NO 2 NAAQS is

included in the docket. 29 We reviewed data from synthetic minor permit appl ications and determined that a typical uncontrolled well pad with two wells would have VOC emissions of about 4,330 tpy.

29 “Impacts of Well Pad VOC Enclosed Combustors and U tility Flares on the Ozone and NO 2 NAAQS”, Memo to file, dated June 15, 2012, from Gail Tonnesen, EPA Region 8 Air Quality Modeler.22

After installing VOC control equipment, including a combination of enclosed combustors, pit flares, an d utility flares with destruction efficiencies rangin g from 90-98%, potential emissions from a typical w ell pad with two wells and no pipeline access were esti mated to be 150 tpy of VOCs. Additionally, EPA projected 8.8 tpy of NO X emissions resulting from the combustion of natural gas emissions at the control device for a two-well pad. Actual emissions are ex pected to be much lower due to the anticipated development of pipeline infrastructure in future ye ars.

The NAAQS for ozone is 75 parts per billion (ppb), and compliance with the NAAQS is determined by comparison to a “design value” that is calculated a s the three year average of the fourth highest dail y eight hour ozone concentration at each monitor site . Based on the most recent ambient monitoring data in North Dakota, the 2011 ozone design values at th e Dunn, TRNP and LNWR sites are 55, 59, and 60 ppb, respectively. 2 We performed a qualitative assessment of impacts on the ozone NAAQS. Ambient ozone is a secondary pollutant that is formed from precursor emissions of VOC and NO X . High ambient ozone levels are typically observed in urban areas during stagnant meteorological conditions during th e summer and more recently, in areas of intensive oil and natural gas production in mountain basins that experience strong inversion conditions and snow cov er during winter. For a typical oil and natural ga s production facility (well pad with two wells), we e stimated that the use of enclosed combustors, utili ty flares, and pit flares would result in VOC reductio ns of about 4,180 tpy and an increase in NO X emissions of 8.8 tpy. We estimated the reasonably foreseeable development of 1,000 well pads with an enclosed combustor and/or utility flare controls wo uld result in a cumulative reduction of 4,180,000 t ons of VOC and an increase of 8,800 tpy of NO X distributed over the FBIR region of 1,544 square m iles. Because the proposed action would result in large V OC reductions and comparatively small NO X increases, the action could result in either net in creases or net decreases in ambient ozone levels depending on the sensitivity of ozone formation to changes in VOC and NO X . Since North Dakota and the FBIR generally have meteorological conditions w ith high winds and good ventilation during the summer ozone season, the emissions changes from the proposed action are not expected to significantly

increase or reduce ambient ozone levels. Elevated winter ozone concentrations have not been observed in North Dakota. However, preliminary analysis of winter ozone in Wyoming indicates that winter

ozone formation is more sensitive to VOC emissions than to NO X emissions. Thus, if high winter ozone

conditions are observed in North Dakota in the futu re, the large VOC reductions from the proposed action would be expected to result in net ozone red uctions on the FBIR.

Based on this qualitative assessment, the emissions changes from the proposed action are not expected to significantly increase or reduce ambient ozone l evels. Given that current ambient ozone levels in North Dakota are substantially lower than the ozone NAAQS, we determined that the proposed action is not expected to cause violations of the ozone NAAQS . We propose to continue to monitor ambient ozone levels in the region, and if increasing level s of ozone are observed in the future, additional analysis of VOCs and NO X impacts on ozone will be performed at that time.

Compliance with the NAAQS for NO 2 is determined by calculating a “design value” whic h is the eighth highest daily one hour average concentration averag ed over a three year period at each monitor site.

2 The Air Quality System (AQS) – the EPA’s Repositor y of Air Quality Data, available online at: http://www.epa.gov/ttn/airs/airsaqs/. The AQS moni toring data for the ND sites can be found in the do cket for the interim final rule, Docket ID: EPA-R08-OAR-2012-0479, which can be accessed at: http://www.regulations.gov23

Source specific model impacts must be combined with background NO 2 concentrations to evaluate potential exceedances of the NO 2 NAAQS. Current background concentrations of NO 2 in the region are quite low. AQS data from 2009 through 2011 shows 1 -hour NO 2 design values for the Dunn, LWNR and TNRP monitors at 11 ppb, 17 ppb, and 9 ppb, res pectively, compared to the standard of 100 ppb. The Dunn monitor site is located about midway betwe en the oil development along the North Dakota –

Montana border and the seven coal conversion facili ties to the east. We selected the Dunn monitor dat a as the most appropriate background site for the FBI R because it is a rural background monitor that is influenced by regional energy development activity.

We performed a quantitative assessment of impacts o n the NO 2 NAAQS. As part of the quantitative analysis, we evaluated various scenarios of NO X emissions from enclosed combustors and utility fla res using the AERMOD nearfield dispersion model to dete rmine the impacts on the 1-hour average ambient

NO 2 NAAQS. Input data to the AERMOD model for enclose d combustors included emission rates of

NO X , stack height and diameter, stack natural gas exit velocity and temperature. Input data for utility flares includes flare height and calories per secon d generated by the enclosed combustor. The AERMOD modeling results did not indicate exceedance s of the NO 2 NAAQS for NO X emissions from utility flares or enclosed combustors. Based on th is analysis, we determined that the proposed action is not expected to cause violations of the NO 2 NAAQS.

We also evaluated the impacts of other pollutants o n the NAAQS. Expected emissions of sulfur dioxide (SO2) and particulate matter (PM) pollutants from e nclosed combustors and utility flares used for control of VOC emissions at well pads are estimated to be below the Federal Tribal NSR permitting thresholds, and are therefore expected to have insi gnificant impacts on the NAAQS for these pollutants

. Expected emissions of carbon monoxide (CO) from the enclosed combustors and utility flares are also expected to have an insignificant impact on the CO NAAQS because of the level of the CO standard in comparison to the emissions.

VI. Executive Order 12898: Federal Actions to Addr ess Environmental Justice in Minority Populations and Low-Income Populations.

Executive Order 12898 (59 FR 7629, February 16, 199 4) establishes federal executive policy on environmental justice. Its main provision directs federal agencies, to the greatest extent practicabl e and permitted by law, to make environmental justice par t of their mission by identifying and addressing, a s appropriate, disproportionately high and adverse hu man health or environmental effects of their programs, policies, and activities on minority popu lations and low income populations in the United

States.

We define “Environmental Justice” to include meanin gful involvement of all people regardless of race, color, national origin, or income with respect to t he development, implementation, and enforcement of environmental laws, regulations, and polices.24

1. Public Participation

To promote meaningful involvement, we will solicit input from potentially affected stakeholders and communities during the public comment period by pos ting information about the proposed rule throughout the reservation at tribal offices, commu nity centers and the Fort Berthold Community College and publishing a notice in five (5) local n ewspapers. In addition, we will hold a public hear ing on the Fort Berthold Indian Reservation during the public comment period.

2. Determination

For purposes of Executive Order 12898 on environmen tal justice, we recognized that compliance with the National Ambient Air Quality Standards (NAAQS) is “emblematic of achieving a level of public health protection that, based on the level of prote ction afforded by a primary NAAQS, demonstrates tha t our issuance of a PSD permit for a proposed facilit y will not have disproportionately high and adverse human health or environmental effects on minority p opulations and low-income populations.” In re Shell Gulf of Mexico, Inc. & Shell Offshore, Inc. , 15 E.A.D. ___, slip op. at 74 (EAB 2010). This i s because the NAAQS are health-based standards, desig ned to protect public health with an adequate margin of safety, including sensitive populations s uch as children, the elderly, and asthmatics. Alth ough taken from the context of issuance of a PSD permit, this logic applies with equal force to our issuanc e of a Clean Air Act Federal Implementation Plan.

We determined that this proposed rule will not have disproportionately high and adverse human health or environmental effects on minority, low income an d indigenous populations because it is in compliance with the NAAQS and provides environmenta l protection for all affected populations without having any disproportionately high and adverse huma n health or environmental effects on any population, including any minority, low income, and indigenous populations.

3. Demographics

Additionally, the Agency has reviewed this rule to determine if there is an overrepresentation of minority, low income, or indigenous populations nea r the sources 30 such that they may currently face disproportionate risks from pollutants that could b e mitigated by this rulemaking. This analysis only gives some indication of the prevalence of sub-popu lations that may be exposed to HAP pollution from the sources affected by this rulemaking; it does no t identify the demographic characteristics of the m ost highly affected individuals or communities, nor doe s it quantify the level of risk faced by those

individuals or communities.

30 Source information on oil and gas wells located on the Fort Berthold Indian Reservation provided by H PDI Inc. 201025

The demographic data in Table 5 shows that several demographic categories exceed 20 percent of their corresponding national averages:

• Native American = +64 percentage points or +5477%

• Minority = +42 percentage points or +152%

• Population under 18 = +6 percentage points or + 25 %

Table 5 - Summary of Demographic Data Analysis

The analysis of demographic data used proximity-to- a-source as a surrogate for exposure to identify those populations considered to be living near affe cted sources, such that they have notable exposures to emissions from these sources. The demographic data for this analysis were extracted from the 2010 census data, which were provided to us by the Unite d States Census Bureau. Distributions by race are based on demographic information at the census bloc k level, and all other demographic groups are based on the extrapolation of census block group level da ta to the census block level. The socio-demographi c parameters used in the analysis included the follow ing categories:

• Racial (White, African American, Native American, O ther or Multiracial, and All Other Races);

• Ethnicity (Hispanic); and

• Other

o Number of people below the poverty line,

o Number of people with ages between 0 and 18,

o Number of people greater than or equal to 65,

o Number of people over age 25 without a high school diploma. POPULATION 6493 312861256

WHITE 1977 30% 226405205 72% -58%

AFRICAN AMERICAN 14 0% 39475216 13% -98%

NATIVE AMERICAN 4221 65% 3646995 1% 5477%

OTHER OR MULTIRACIAL 281 4% 43333840 14% -69%

MINORITY 2 4516 70% 86456051 28% 152%

HISPANIC OR LATINO 3 272 4% 54181245 17% -76%

AGE 0 - 17 1955 30% 75217176 24% 25%

AGE 65+ 657 10% 40830262 13% -22%

NO HIGH SCHOOL DIPLOMA 383 6% 31914536 10% -42%

BELOW POVERTY LINE 838 13% 43487509 14% -7%

>= 1.2 of National Average %
Change DEMOGRAPHIC SUMMARY 1 NEAR

SOURCE NATIONAL

TOTAL % OF NEAR

SOURCE % OF

NATIONAL

Sources: The demographics are from the U.S. Census Bureau, 2010. Information on the facilities is from U.S. EPA.

1. Racial and ethnic categories overlap and cannot be summed.

2. The “Minorities” population is the overall popul ation (in the first column) minus white population (in the second column).

3. The Census Bureau defines “Hispanic or Latino” a s an ethnicity rather than as a racial category, Hi spanics or Latinos may belong to any race.26

In determining the aggregate demographic makeup of the communities near affected sources, we

focused on those census blocks within 3 miles of af fected sources and determined the demographic composition (e.g., race, income, etc.) of these cen sus blocks and compared them to the corresponding compositions nationally. The radius of 3 miles (or approximately 5 km) is consistent with other demographic analyses focused on areas around potent ial sources 31

, 32

, 33

, 34 however, not necessarily

associated with the distance health risks are seen. To the extent that any minority, low income, or indigenous subpopulation is disproportionately impa cted by the emissions as a result of the proximity of their homes to these sources, that subpopulation al so stands to see increased environmental and health benefit from the emission reductions called for by this rule.

Because this study area is primarily on a reservati on, a second analysis examined if predominantly Native Americans block groups had other environment al justice concerns. Table 6 compares demographic information for the Native American blo ck groups to national averages. Besides race, the poverty rate and age demographics are the major dif ferences between the predominately Native Americans and national averages. The overall study area has a poverty rate 7 percent below the nation al average, while the areas of concentrated native Ame ricans has a poverty rate of 28 percent, which is 1 03 percent higher than the national average (28 percen t vs. 14 percent).

31 U.S. GAO (Government Accountability Office). Demog raphics of People Living Near Waste Facilities. Was hington DC: Government Printing Office; 1995.

32 Mohai P, Saha R. “Reassessing Racial and Socio-eco nomic Disparities in Environmental Justice Research ”. Demography. 2006;43(2): 383–399.

33 Mennis J. “Using Geographic Information Systems to Create and Analyze Statistical Surfaces of Populat ions and Risk for Environmental Justice Analysis”. Social Science Qua rterly, 2002;83(1):281-297.

34 Bullard RD, Mohai P, Wright B, Saha R, et al. Toxi c Waste and Race at Twenty 1987-2007. United Church of Christ. March, 2007.27 Table 6 - Block Groups with 50% of More Native Amer icans

Table 7 compares the Native American block groups w ith the white block groups. The Native American population is 520 percent higher than in the predom inately white block groups (71 percent vs. 11 percent), poverty level 138 percent higher (28 perc ent vs. 12 percent), the population under 18 years of age is 40 percent higher (31 percent vs. 23 percent ), and population below five years is 56 percent hi gher (9 percent vs. 6 percent).

Demographic

Summary 1 Native

American

Areas % Of Native

American

Areas National

Totals % Of

National

Totals % Change

POPULATION 5,815 312,861,256

WHITE 1,437 25% 226,405,205 72% -66%

AFRICAN AMERICAN 7 0% 39,475,216 13% -99%

NATIVE AMERICAN 4,120 71% 3,646,995 1% 5978%

OTHER OR MULTIRACIAL 251 4% 43,333,840 14% -69%

MINORITY 2 4,378 75% 86,456,051 28% 172%

HISPANIC OR LATINO 3 260 4% 54,181,245 17% -74%

AGE 0 - 4 537 9% 20,465,068 7% 41%

AGE 0 - 17 1,826 31% 75,217,176 24% 31%

AGE 65+ 528 9% 40,830,262 13% -30%

NO HIGH SCHOOL

DIPLOMA 496 9% 32,060,510 10% -17%

BELOW POVERTY LINE 1,643 28% 43,616,850 14% 103%

>= 1.2 times National Average

Sources: The demographics are from the U.S. Census Bureau, 2010. Information on the facilities is from U.S. EPA.

1. Racial and ethnic categories overlap and cannot be summed.

2. The “Minorities” population is the overall popul ation (in the first column) minus white population (in the second column).

3. The Census Bureau defines “Hispanic or Latino” a s an ethnicity rather than as a racial category, Hi spanics or Latinos may belong to any race.

4. Where facility study areas overlap, the census b lock populations are only counted once. Therefore, a facility level total will not match this summary total.28 Table 7 - Comparing Native American Block Groups to Remaining Study Area

VII. Conclusion

We believe that in light of the regulatory gap and potential for future air quality issues related to VOC generally presented on the FBIR, it is appropriate to establish the air quality rule that is proposed today. By means of the proposed rule, we will impose regul atory requirements on the oil and natural gas production industry on the FBIR, equivalent to thos e imposed by the NDDoH rules for the areas outside the FBIR. We believe that it is appropriate to foc us initially on the oil and natural gas production operations that have been identified as having the greatest potential to impact future air quality on the

FBIR and in shared airsheds of North Dakota.

This rule would regulate activities, pollutants, an d facilities by supplementing the existing federal regulatory programs such as the PSD, Minor NSR, Tit le V, NSPS, and NESHAP programs. This proposed rule would provide additional regulatory t ools for us to use in implementing the CAA on the FBIR. We have adequate enforcement authority under Section 113 of the CAA to ensure compliance with the requirements that are proposed.

Demographic

Summary 1 Native

American

Areas % Native

American

Areas White Areas % White

Area % Change

POPULATION 5,815 9,976

WHITE 1,437 25% 8,593 86% -71%

AFRICAN AMERICAN 7 0% 20 0% -40%

NATIVE AMERICAN 4,120 71% 1,140 11% 520%

OTHER OR MULTIRACIAL 251 4% 223 2% 93%

MINORITY 2 4,378 75% 1,383 14% 443%

HISPANIC OR LATINO 3 260 4% 190 2% 135%

AGE 0 - 4 537 9% 590 6% 56%

AGE 0 - 17 1,826 31% 2,245 23% 40%

AGE 65+ 528 9% 1,573 16% -42%

NO HIGH SCHOOL

DIPLOMA 496 9% 1,054 11% -19%

BELOW POVERTY LINE 1,643 28% 1,183 12% 138%

>= 1.2 times Total Study Area

Sources: The demographics are from the U.S. Census Bureau, 2010. Information on the facilities is from U.S. EPA.

1. Racial and ethnic categories overlap and cannot be summed.

2. The “Minorities” population is the overall popul ation (in the first column) minus white population (in the second column).

3. The Census Bureau defines “Hispanic or Latino” a s an ethnicity rather than as a racial category, Hi spanics or Latinos may belong to any race.

4. Where facility study areas overlap, the census b lock populations are only counted once. Therefore, a facility level total will not match this summary total.29

Regulating these sources is appropriate not only in order to protect air quality from the potential fo r significant deterioration caused by the release of VOC, but also to ensure equal incentive for operato rs to develop the mineral resource on Tribal versus st ate land. VOC is regulated indirectly by National Ambient Air Quality Standards (NAAQS) as a precurso r to ozone formation under section 109 of the CAA. The rule proposed today would control emissio ns of VOC to the atmosphere as appropriate for the purpose of maintaining or attaining the NAAQS f or ozone. Along with the protections this Federal air quality rule would provide, the rule can also a ssist the Three Affiliated Tribes of the Mandan, Hidatsa, and Arikara Nations in developing an air q uality management program by using the federal rule as a template in drafting a TIP.

The FBIR is currently experiencing one of the large st oil and natural gas booms the nation has ever experienced. Oil and natural gas development is ex pected to continue to increase significantly in the future, thus increasing the total VOC emissions in the area.

Due to the current lack of pipeline infrastructure, the use of pit flares, utility flares, and enclose d combustors are standard industry practice for contr olling VOC emissions at oil and natural gas production facilities on the FBIR. We determined i t is necessary to promulgate a FIP to regulate the affected equipment and reduce the environmental imp act of increasing oil and natural gas development in the area. The emission control requirements in the FIP will provide up to 98% reduction in these emissions, greatly reducing the environment impact of the booming oil and natural gas industry on the

FBIR.

We believe that this rule is appropriate because it establishes federally enforceable requirements to control VOC emissions from oil and natural gas prod uction equipment equivalent to the requirements imposed by the NDDoH, which will allow owners and o perators to take into account controls they would use (and are already using) regardless of any federally enforceable requirement. Thus, the FIP equalizes the playing field between NDDoH jurisdict ion and our jurisdiction on the FBIR. Additionally

, the FIP will reduce the permitting burden for us, t hereby preventing potential delays in development o f the economically valuable mineral resource, because many facilities will be able to commence construction without first having to obtain a const ruction permit.