Matthew Todd

Regulatory and Scientific Affairs

1220 L Street, NW

Washington, DC 

20005-4070 USA

Telephone: 202-682-8319

Fax: 202-682-8031

Email: ToddM@api.org

www.api.org

via e-mail 

July 25, 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 prepublication final rule entitled “Oil and Natural Gas Sector: New Source Performance Standards and 

National Emission Standards for Hazardous 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 the 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 and direction in 

response to these 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

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

effective date (60 days after publication in the Federal Register), to both allow venting and only 

require its minimization during these periods.

Thank you for your consideration of this request. Please do not hesitate to contact me (202.682.8319) if you 

have any questions. 

Sincerely, 

/s/

Matthew Todd 

cc: P. Tsirigotis

D. Cozzie
Critical 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 crude 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 permanent 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 intend 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 “screenout” 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 well 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. Although 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 completion 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 this section.” API 

believes this means that compliance with (a)(1) and (2) is not required and that any recovery of natural 
gas or hydrocarbon liquids is unregulated before January 1, 2015. Others have opined that this 

interpretation would make the language 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 have 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 RTC 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 the 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 enforceable 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 intend 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 into 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) specifies 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 publication 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 requirements 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, “Equipment 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, completions, 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 definition 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, 

alternative 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 to 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?