Matthew Todd

Regulatory and Scientific Affairs

1220 L Street, NW Washington, DC

20005

- 4070 USA Telephone: 202

- 682

- 8 319
Fax: 202

- 682

- 8031
Email: ToddM@api.org www.api.org

via e

- mail

July 2 5 , 2012

Mr. Bruce Moore U.S. Environmental Protection Agency

109 T.W. Alexander Drive

Mail Code: E143

- 01 Research Triangle Park, NC 27709

Re: Oil and Natural Gas Sector Consolidated Rulemaking,

Docket ID No. EPA

- HQ

- OAR

- 2010

- 0505

Mr. Bruce Moore :

On behalf of the American Petroleum Institute (API), I am writing regarding the April 17, 2012 pre

publication final rule entitled “ Oil and Natural Gas Sector: New Source Performance Standards and

National Emission Standards for Hazard ous Air Pollutants Reviews

. ” API is a national trade association with

over 500 member companies that are involved with all aspects of the oil and natural gas industry.

API has identified several issues with the final rule that will significantly impact t he planning, capital

investment, and time for installation of required controls in order to comply by the appropriate effective or

compliance date (see attached list)

. As such, we believe timely clarification of EPA’s intent a nd direction in

response to t hese questions will be critical for implementation planning that will begin immediately upon

publication of the final rule in the Federal Register.

I also bring to your attention a separate issue that , we believe, could have significant and immediate

impl ications sixty days from publication of the final rule in the Federal Register. In the proposed rule , EPA

clearly allowed venting of gas during flowback when the combustion of vapors is infeasible and it’s our

interpretation that the final rule does not al low this. The same equipment to conduct a “reduced emission

completion” (REC) is needed to separate vapors and route them to a combustion device during the initial

periods of hydraulic fracture flowback . As you know, the EPA provided a phase

- in period for the REC

requirements (until January 1, 2015) to allow adequate time to manufacture this equipment to meet the newdemands

. Therefore, we believe it is imperative that the EPA revise the regulatory text, prior to the

effective date (60 days after publicatio n in the Federal Register)

, to both allow venting and only

require its min imization during these periods

.

Thank you for your consideration of th is request. P lease do not hesitate to contact me (202.682.8319) if you

have any questions.

Sincerely,

/s/

Matthew Todd

cc: P. Tsirigotis

D. CozzieCritical Implementation Questions on Final Oil and Gas NSPS/NESHAP Rule

Gas Well Completions

1. The requirement in 60.5375(a)(1) to ‘route the recovered liquids into one or more storage vessels” is causing several concerns, including EPA did not define recovered liquids and because storage vessel is defined later in the rule which excludes portable tanks on site less than 180 days.

a. API believes that the term “recovered liquids” means saleable hydrocarbon liquids such as condensate or crude oil. That was clearly EPA’s intent in the proposed rule and there is no evidence to indicate a change in the final rule. Did EPA intend recovered liquids to means saleable hydrocarbon liquids, such as condensate or crud e oil?

b. The term “storage vessel” as defined in the rule excludes portable tanks on site less than 180 days. Portable tanks are often used during flowback following hydraulic fracturing. Did EPA intend to require recovered liquids to be placed in permanen t storage vessels as defined in the rule or can temporary or portable “fracture tanks” be used?

2. Digital Photo Requirements. There are multiple concerns with the addition of digital photograph requirement for record keeping for completions.

a. Did EPA inte nd allow the digital photograph as an alternative to the recordkeeping and reporting requirements?

b. There are only a few camera models that are available with GIS coordinates. Even cameras that have GIS capability do not have the latitude and longitude in this specific format and 5 decimals of a degree of accuracy. Does the digitial photograph have to meet the requirements of 60.5420(a)(1)(i) for “the latitude and longitude coordinates for each well in decimal degrees to an accuracy and precision of five (5) decimals of a degree using the North American Datum of

1983”?

c. Because cameras are not intrinsically safe for operation in a potentially explosive atmosphere, there will be some discrepancy between the lat/long coordinate of the camera relative to the REC equipment. Is it sufficient that the latitude and longitude of the photograph is close to the well latitude and longitude?

3. Processes during hydraulic fracturing

– There are processes performed during hydraulic fracturing that

are not associated with flowback following hydraulic fracturing. API would like confirmation in guidance or the preamble that screenouts and coil tubing clean outs are not subject to the requirements of the Oil and Gas NSPS for gas wells.

a. Screenouts

– While infrequent, a “screen out” is the first attempt to clear the proppant (sand) that can plug the wellbore. It involves flowing the well to a fracture tank to achieve maximum velocity to carry the sand out of the well. Although unlikely, small amounts of gas and condensate may be part of the flowback fluids during screenouts. Are screenouts subject to the requirements of the Oil and Gas NSPS for gas wells?

b. Coil Tubing Cleanouts

– If a screenout is unsuccessful in clearing the packed proppant (sand) from

the well

- bore, then the we ll is typically “jetted” using a coil tubing unit. This involves running a string of coil tubing to the proppant pack and jetting the well, typically with nitrogen gas, to dislodge the sand and provide sufficient lift energy to flow it to surface. Althou gh not likely, it is possible to have small amounts of gas and/or condensate in the flow

- back fluids during such an operation. Are coil tubing cleanouts subject to the requirements of the Oil and Gas NSPS for gas wells?

4. 60.5375(a) states “for each well c ompletion operation with hydraulic fracturing begun prior to January 1, 2015, you must comply with the requirements of paragraphs (a)(3) and (4) of this section . . . ; optionally, you may comply with the requirements of paragraphs (a)(1) through (4) of th is section.” API believes this means that compliance with (a)(1) and (2) is not required and that any recovery of naturalgas or hydrocarbon liquids is unregulated before January 1, 2015. Others have opined that this interpretation would make the languag e about “paragraphs (a)(1) through (4)” unnecessary and its inclusion mandates complying with (a)(1)

- (4) if any natural gas or hydrocarbon liquids are recovered. If (a)(1)

- (4) can be enforceable, then API has critical issues concerning (a)(1)

- (2) that hav e not yet been defined that must be resolved immediately. Did EPA intend that hydrocarbon recovery before January 1, 2015 to be unregulated?

5. EPA did not respond to our concern that the combustion provisions would conflict with local regulations

in the RT C document, even though they did summarize this comment (see p.58). Durango, CO does not allow flaring, but it is not due to fire or explosion hazard per se. Are areas with local regulations (state, city, county, etc.) precluding flaring exempt from the flaring requirements?

Storage Vessels

6. API continues to believe that NSPS, Subpart OOOO will apply to approximately 28,000 storage vessels/year as currently written. EPA believes that Subpart OOOO will apply to only 304 storage vessels as indicated by th e TSD. One possible explanation for the difference between tank count is confusion about the basis of the 6 tpy VOC control threshold. API has based its estimate on uncontrolled emissions as discussed in the Response to Comments. However, the TSD stated that many vessels would be under the 6 tpy VOC threshold as a result of state or local regulations. This appears to support a “federally enforceable PTE” basis for the 6 tpy threshold . Did EPA intend the 6 tpy threshold to be based on “federally enforceab le PTE”?

7. The provisions of §60.5395(a)(1)&(2) and §60.5410(e)(1)

- (4) apply the standards to storage vessels “at a well site.” Furthermore, §60.5412(a) cites §60.5395(a)(1)&(2), and is thus specific to storage vessels at

a well site.

a. Did EPA only inte nd these sections to apply only to storage tanks at well sites?

b. What if any requirements apply to storage vessels at other production facilities, such as at compressor stations and gas plants?

8. A common practice for controlling storage vessel emissions in the oil and natural gas production segment is to route vapors from the storage vessels back to the inlet line of a separator, to a sales gas line, or to some other line carrying hydrocarbon fluids. A compressor is used to boost the recovered vapors in to the line, that is often referred to as a “vapor recovery unit” (VRU), even though it does not

involve an end

- of

- line control device. EPA did not include exclusion for this type of a VRU, but also did not provide any regulatory text regulating this type of VRU. Did EPA intend to exclude VRUs that recycle gas back to the process similarly to NESHAP, Subpart HH?

Performance Testing

9. Initial performance testing requirements and the storage vessel compliance date appear to be in conflict. §60.5410(e)(5) s pecifies that initial performance tests must be conducted with 180 days of initial startup or within 180 days of publication of the rule in the Federal Register. However, storage vessels are not required to be equipped with controls until 1 year after pub lication in the Federal Register, per §60.5395.

Does EPA intend to reconcile these schedules?

Compressors

10. In §60.5420(a)(1), EPA specifically excluded gas well, pneumatic controller, and storage vessel affected facilities from the notification requirem ents in §60.7(a)(1), (a)(3) and a(4). However, EPA did not specifically exclude reciprocating and centrifugal compressor affected facilities in the same paragraph. Did EPA intend for owners or operators to submit notifications required in §60.7(a)(1), (a) (3) and a(4) for centrifugal and reciprocating compressor affected facilities? If so, what is unique about compressors to justify the additional notification requirements?Equipment Leaks

11. Definition of Equipment As currently defined in §60.5430, “ Equi pment means each pump, pressure relief device, open

- ended valve or line, valve, and flange or other connector that is in VOC service or in wet gas service, and any device or system required by this subpart

. ” Without a clarification from EPA and a revision to the rule language, this same phrase in Subpart OOOO could be interpreted as to include not only any device or system required by the equipment leaks provisions of the rule, but also those required by provisions for storage vessels, compressors, complet ions, etc. This would greatly expand the scope of the equipment leaks program under Subpart OOOO when compared with Subpart KKK. API believes this was not

EPA’s intent.

Did EPA intend the phrase “any device or system required by this subpart” in the de finition of “equipment” to be limited to the device or system required by the equipment leak provisions of §§60.5400, 60.5401, and 60.5402?

Other

12. Prior to rule proposal, EPA had indicated to EPA that provisions in the rule would be made for new,

alternat ive control technologies. Currently, the final rule is prescriptive for storage vessel controls, and there are no provisions in the rule for new or alternative technologies. This would seem to stifle

innovation of emissions control.

a. Was it EPA’s intent t o explicitly prohibit any new control technologies from ever being used or is it an inadvertent omission to not include language that allows for review and adoption of new technology?