Oil and Natural Gas Sector: Reconsideration of Certain Provisions of

New Source Performance Standa rds

40 CFR Part 60

Response to Public Comments on

P roposed Rule (7 8 FR 22126 ; April 12, 2013 )

U

. S

. Environmental Protection Agency

Office of Air Quality Planning and Standards Sector Policies and Programs Division Research Triangle Park, NC 27711

July 2013i 

### Table of Contents

1.0 Summary

................................ ................................ ................................ ................................ ... 1

1.1 Background

................................ ................................ ................................ ........................... 1

1.2 Summary of Significant Changes Since Proposal

................................ ................................ 6

1.2.1 Initial Notification and Compliance Dates

................................ ................................ .... 6

1.2.2 Group 1 and Group 2 Storage Vessel Emission Standard Applicability

....................... 6

1.2.5 Definition of Storage Vessel

................................ ................................ .......................... 7

1.2.7 Streamlined Compliance Monitoring Provisions

................................ ........................... 7

1.2.8 Combustor Control Device Manufacturer Test Protocol

................................ ............... 7

1.2.9 Annual Report and Compliance Certification

................................ ................................ 7

1.3 Summary of Impacts of Reconsideration

................................ ................................ .............. 7

2.0 Response to Comments Regarding Subpart OOOO

................................ ................................ . 8

2.1 Storage Vessel Applicability

................................ ................................ ................................ . 8

2.1.1 Storage Vessel Affected Facility

................................ ................................ ................... 8

2.1.2 Storage Vessel Applicability Determination

................................ ............................... 13

2.2 Storage Vessel Control Requirements

................................ ................................ ................ 32

2.2.1 Gener al Support for Group 1 Storage Vessel Requirements

................................ ....... 32

2.2.2 Control Equipment Design Requirements

................................ ................................ ... 32

2.2.3 Electronic Ignition Systems

................................ ................................ ......................... 34

2.2.4 Flares

................................ ................................ ................................ ............................ 36

2.2.5 Carbon Adsorption

................................ ................................ ................................ ....... 37

2.2.6 Control Device Opera ting Requirements

................................ ................................ ..... 37

2.2.7 Storage Vessel Alternative Control Requirement

................................ ........................ 39

2.3 Storage Vessel Recordkeeping Requireme nts

................................ ................................ .... 40

2.4 Storage Vessel Notification and Reporting Requirements

................................ ................. 41

2.4.1 Initial Notification Exemption for Compressors

................................ .......................... 41

2.4.2 Initial Notification for Group 1 Storage Vessels

................................ ......................... 41

2.4.3 Responsible Official

................................ ................................ ................................ ..... 42

2.4.4 Rep orting Deadline

................................ ................................ ................................ ...... 44

2.5 Compliance Demonstration and Monitoring Provisions

................................ ..................... 45ii

2.5.1 Vapor Recovery Units

................................ ................................ ................................ .. 45

2.5.2 Leaking Closed Vent Systems and Covers

................................ ................................ .. 45

2.5.3 Performance Testing

................................ ................................ ................................ .... 46

2.5.4 Compliance Monito ring Requirements

................................ ................................ ........ 53

2.5.5 Startup, Shutdown and Malfunction

................................ ................................ ............ 54

2.6 Compliance Schedule

................................ ................................ ................................ .......... 55

2.7 Number of Storage Vessels at Different Throughput Levels (“Higher Emitting”)

............ 56

2.8 Small Business Impacts

................................ ................................ ................................ ...... 57iii Acronyms and Abbreviations

API American Petroleum Institute

BACT Best Available Control Technology

BPD Barrels Per Day

BSER Best System of Emission Reduction

CAA Clean Air Act

CFR Code of Federal Regulations

CO Carbon Monoxide

CO 2 Carbon Dioxide

EPA Envir onmental Protection Agency

ERPG Emergency Response Planning Guidelines

ERT Electronic Reporting Tool

MACT Maximum Achievable Control Technology

NO X Oxides of Nitrogen

NSPS New Source Performance Standards
OAQPS Office of Air Quality Planning and Standards

OMB Office of Management and Budget

PTE Potential to Emit

RTC Response to Comments

SO 2 Sulfur Dioxide

SSM Startup, Shutdown and Malfunction

TPY Tons per Year

VOC Volatile Organic Compounds

VRU Vapor Recovery Unit1 

### 1.0 Summary

1.1 Background

On January 14 , 2009, pursuant to section 304(a)(2) of the Clean Air Act (CAA), WildEarth Guardians and the San Juan Citizens Alliance filed a Complaint alleging that the U.S. Environmental Protection Agency (EPA) failed to meet its obligations under CAA sections 111(b) (1)(B), 112(d)(6) and 112(f)(2) to take actions relative to the review/revision of the new source performance standards (NSPS) and the national emissions standards for hazardous air pollutants (NESHAP) with respect to the Oil and Natural Gas Production sou rce category. On February 4, 2010, a consent decree was entered that, as modified, required the EPA to sign by July 28, 2011, proposed standards and/or determinations not to issue standards pursuant to CAA sections 111(b)(1)(B), 112(d)(6) and 112(f)(2) and to take final action by April 3, 2012.

On August 8, 2011, the EPA announced (76 FR 52738) how the Agency proposed to address the reviews of the new source performance standards (NSPS) for volatile organic compound (VOC) and sulfur dioxide (SO 2 ) emissions from natural gas processing plants. The EPA proposed to add to the source category list any oil and gas operation not covered by the current listing. This action also included proposed amendments to the existing NSPS for VOCs from natural gas processing p lants and proposed standards for operations not covered by the existing NSPS. In addition, this action proposed how the EPA would address the residual risk and technology review (RTR) conducted for the oil and natural gas production and natural gas

transmi ssion and storage national emission standards for hazardous air pollutants (NESHAP). The EPA further proposed standards for emission sources within these two source categories that were not then addressed, as well as amendments to improve aspects of these NESHAP related to applicability and implementation. Finally, the EPA addressed provisions in these NSPS and NESHAP related to emissions during periods of startup, shutdown and malfunction (SSM).

On August 16, 2012, the EPA published final NSPS and NESHAP for the oil and natural

gas sector (77 FR49490) . The Adminis trator received petitions for reconsideration of certain aspects for the standards.

On April 12, 2013, the EPA announced their proposed amendments to the oil and natural gas sector NSPS as a res ult of reconsideration of certain issues related to implementation of storage vessel provisions. Twenty

- six comment letters were received on the proposed

amendments and entered into the EPA’s Air and Radiation docket assigned for this rulemaking ( docket nu mber EPA

- HQ

- OAR

- 2010

- 0505). The EPA reviewed all of the comment letters

entered into the docket.

This document presents a summary of the public comments entered into docket EPA

- HQ

OAR

- 2010

- 0505 regarding specific issues and topics related to the developme nt of the proposed subpart OOOO NSPS (40 CFR part 60) amendments and the EPA’s responses to those

comments. The EPA assigned these comments to specific categories (see Table of Contents) based on an assessment of the principal subject of the comment; howev er, some comments inevitably overlap multiple subject areas. Table 1 provides the list of comments received by2

docket document ID, the commenter and their affiliation. The last 4 digits of the docket document ID are used to identify comments summarized and responded to in this document.3

Table 1

. List of Commenters on the Oil and Natural Gas Sector: Reconsideration of Certain Provisions of

New Source Performance Standards; P roposed Rule (78 FR 22126; April 12 , 201 3)

Document ID N ame and Affiliation Date Received

EPA

- HQ

- OAR

- 2010

- 0505

- 4609 Comment submitted by S.
Akhmetkaliyeva 4/21/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4610 Anonymous public comment 4/26/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4611 Comment submitted by William C.

Allison V, Director, Air Pollution

Control Division, Colorado
Department of Public Health and

Environment 5/13/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4612 Comment submitted by Thure
Cannon, President, Texas Pipeline
Association (TPA) 5/13/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4613 Comment submitted by G retchen C.
Kern, Regulatory Advisor,
Sustainable Development, Pioneer

Natural Resources USA, Inc. 5/24/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4614 Comment submitted by Mark W.
Sommer, General Manager, Power
Ignition and Controls, LLC (PIC
Appalachia) 5/28/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4615 Comment submitted by Jeff
Applekamp, Director, Government

Affairs, Gas Processors Association

(GPA) 5/28/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4616 Comment submitted by R. Andrew

Smith, Advanced Burner
Technologies (ABUTEC) 5/28/2013

EPA

- HQ

- OAR

- 2 010

- 0505

- 4617 Comment submitted by Kathleen M.
Sgamma, Vice President,

Government and Public Affairs,
Western Energy Alliance 5/28/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4618 Comment submitted by Zak Covar,

Executive Director, Texas

Commission on Environmental
Quality (TCEQ) 5/28/20134 Document ID N ame and Affiliation Date Received

EPA

- HQ

- OAR

- 2010

- 0505

- 4619 Comment submitted by Mickey
Thompson, Executive Director,
Domestic Energy Producers Alliance

(DEPA) 5/28/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4620 Comment submitted by Amy Farrell,
Vice President of Regulatory

Affairs, Am erica ’ s Natural Gas
Alliance (ANGA) and V. Bruce
Thompson, President, American
Exploration and Production Council

(AXPC) 5/28/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4621 Comment submitted by Andrew V.

McNeill, Executive Director,
Kentucky Oil and Gas Association

(KOGA ) 5/28/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4622 Comment submitted by David

McCabe, Clean Air Task Force et al. 5/28/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4623 Comment submitted by Cory
Pomeroy, General Counsel, Texas
Oil & Gas Association (TXOGA) 5/28/2013

EPA

- HQ

- OAR

- 2010

- 05 05

- 4624 Comment submitted by Alice

Edwards, Director, Division of Air
Quality, Alaska Department of

Environmental Conservation

(ADEC) 5/28/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4625 Comment submitted by Nikki C.
Martin, Regulatory and Legal
Affairs Manager, Alaska Oi l and
Gas Association (AOGA) 5/29/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4626 Comment submitted by James D.
Elliott, Spilman Thomas & Battle,

PLLC on behalf of Lee O. Fuller,

Vice President of Government
Relations, Independent Petroleum
Association of America (IPAA) 5 /28/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4627 Comment submitted by Laura J.
Finley, Air Quality Attorney, Office

of the General Counsel, Oklahoma 5/28/20135 Document ID N ame and Affiliation Date Received

Department of Environmental
Quality (ODEQ)

EPA

- HQ

- OAR

- 2010

- 0505

- 4628 Comment submitted by John

Robitaille, Vi ce President,
Petroleum Association of Wyoming

(PAW) 5/28/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4629 Comment submitted by Kyle D.
Shotts, Manager, Combustion Rental
and Rapid Execution Group, Zeeco,

Inc. 5/28/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4630 Comment submitted by Matth ew Todd, Senior Policy Advisor,
American Petroleum Institute (API) 5/28/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4631 Comment submitted by Louis D.

D'Amico, President and Executive
Director, Pennsylvania Independent
Oil and Gas Association (PIOGA) 5/24/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4632 Comment submitted by Matthew S.

Stone, President, Indiana Oil and
Gas Association (INOGA) 6/3/2013

EPA

- HQ

- OAR

- 2010

- 0505

- 4633 Comment submitted by Adrian
Araiza, Manager, Air Quality
Compliance, Cimarex Energy Co. 6/3/2013

EPA

- HQ

- OAR

- 2010

- 0 505

- 4634 Comment submitted by Barry T.

Smitherman, Chairman et al.,

Railroad Commission of Texas 6/4/20136



### 1.2 Summary of Changes Since Proposal

This section describes significant changes made to the reconsideration proposal that the

EPA is now finaliz ing in this rule. These changes result from the EPA’s review of the additional data and information provided to us and our consideration of the many substantive and thoughtful comments submitted on the proposal.

1.2.1 Initial Notification and Compliance D ates

For Group 1 storage vessel affected facilities, we have amended the 2012 NSPS to require that a notification be submitted with the initial annual report to inform regulatory agencies of the existence and location of the vessels. In addition, we have amended the 2012 NSPS to require that all Group 1 storage vessel affected facilities comply with the emission standards no later than April 15, 2015 and that all Group 2 storage vessel affected facilities comply with emission standards no later than April 15, 2014 (or 6 0 days after startup, whichever is later).

The final amendments also make clarifying changes to §60. 53 6 5 that clearly specify October 15, 2013, as the deadline for calculating potential VOC emissions from Group 1 storage

vessels to determi ne affected facility status.

1.2.2 Group 1 and Group 2 Storage Vessel Emission Standard Applicability

We have amended §60.5395 to clearly state that the emission standards apply to Group 1 and Group 2 storage vessel affected facilities (as opposed to al l storage vessels).

1.2.3 Group 1 Storage Vessel Affected Facility Control Requirements

The final amendments retain the requirement in the 2012 NSPS that all storage vessel affected facilities meet the emission standards. However, the final amendments r equire that owners and operators of Group 1 storage vessel affected facilities comply with the emission standards by April 15, 2015.

1.2.4 Alternative 4

- tpy Uncontrolled Actual Emission Rate

We have amended the storage vessel standards to include a sust ained uncontrolled actual VOC emission rate of less than 4 tpy. Specifically, an owner or operator may comply with the uncontrolled actual VOC emission rate instead of the 95 percent control requirement where it can be demonstrated that, based on records o f monthly emission estimates for the 12 months immediately preceding the demonstration, that the storage vessel affected facility uncontrolled actual VOC emissions estimated each of those months were below 4 tpy. The owner or operator would be required to re

- evaluate the uncontrolled actual VOC emissions on a monthly basis to
ensure that emissions do not reach 4 tpy.7

1.2.5 Definition of Storage Vessel

The final amendments revise the definition of “storage vessel” to clarify that it refers only

to vess els containing crude oil, condensate, intermediate hydrocarbon liquids or produced water.

1.2. 6 Definition of Storage Vessel Affected Facility

The final amendments revise the definition of “storage vessel affected facility” (see §60.5365(e)) to (1) inc lude the 6 tpy VOC emission threshold and to clarify that a source can take into account any legally and practically enforceable emission limit under federal, state, local or tribal authority when determining the VOC emission rate for purposes of this thre shold; (2) clarify that a storage vessel affected facility whose VOC PTE decreases to less than 6 tpy would remain an affected facility; (3) replace the term “other mechanisms” with “other requirements”

and clarif y that such requirements must be legally an d practically enforceable under federal, state, local or tribal authority; and (4) allow PTE determination to exclude any vapor from the storage vessel that is routed to a process via a closed vent system designed and operated according to the closed vent requirements in the final amendment s

.

1.2. 7 Streamlined Compliance Monitoring Provisions

For storage vessels that install controls to meet the 95 percent VOC reduction standard, we have amended the 2012 NSPS to adopt the streamlined compliance monitorin g provisions as proposed without significant changes. These compliance monitoring provisions include inspections performed at least monthly of covers, closed

- vent systems and control devices. W e continue to evaluate the reconsideration issues raised concer ning the compliance monitoring provisions in the 2012 NSPS and intend to complete our reconsideration by the end of 2014.

1.2.8 Combustor Control Device Manufacturer Test Protocol

We have finalized amendments to the combustor control device manufacture r test protocol in the NSPS to align it with a similar protocol in the Oil and Natural Gas National Emission Standards for Hazardous Air Pollutants (NESHAP) (40 CFR 63, subpart HH).

1.2.9 Annual Report and Compliance Certification

We finalized amendment s to allow 90 days after the end of the compliance period for submittal of the annual report and compliance certification.



### 1.3 Summary of Impacts of Reconsideration

Owners and operators of storage vessel affected facilities are expected to install and

o perate the same or similar control technologies under these final amendments as would have been necessary to meet the previously finalized standards under the 2012 NSPS. We project that these amendments will not result in a significant change in costs or b enefits. Since we believe

that the same controls will be used for th ese final amendments as would have been used for the

2012 final rule, there should not be any incremental costs related to this proposed revision.8 

### 2.0 Response to Comments Regarding Subpa rt OOOO

2.1 Storage Vessel Applicability

2.1.1 St orage Vessel Affected Facility

2.1.1.1 Deadline for Determining Whet h er a Storag e Vessel is an Affected Facility

Comment: Several commenters ( 4613, 4617, 4620, 4626 , 4631, 4633 ) request that the

EPA cons ider a longer timeframe to determine VOC emissions from Group 2 storage vessels. A few of the commenters (4613, 4617, 4626) recommend a minimum of 90 days be allowed (versus the 60 days proposed) to determine emissions and install ay necessary controls

.

O ne commenter (4613) requests a 90 day versus 60 day timeframe to evaluate emissions and install any necessary controls. The commenter recommends that the emissions evaluation period and control device installation period for all storage vessels (including Group 1 vessels) that have a triggering even t , run simultaneously and should be extended to at least 90 days. The commenter provides that production and emissions data reportedly are often not available until up to 60 days after the date of first productio n
, and procuring a control device, plus installation, can take weeks to months depending on the availability of controls. Further, according to the commenter, it is impossible to know at this point if the control device market will be able to keep pace wit h the demand so additional time is reasonable, given the uncertainties.

One commenter (4633) is concerned about the availability of flare control devices to meet the compliance provisions and compliance date of April 15, 2014

, for affected Group 2

storage vessels. The commenter requests that the EPA extend the compliance date for Group 2 storage vessels. Alternatively, the commenter requests that the EPA raise the PTE VOC emissions threshold above the already established 6 tpy to only control higher emitti ng storage vessels by April 15, 2014.

One commenter ( 4626 ) requests that the EPA ex tend the proposed deadline for Group 2 storage vessels, who must de termine VOC emissions by April 15, 2014, or 30 days after startup.

The commenter asserts that these time periods are too short. The commenter recommends that, a t a minimum, 90 days is necessary to conduct the required emissions calculation and install

controls. The commenter asserts that the first 30 days of production normally are not representative of stabi lized production from a well, and are subject to variation that could result in the overestimation or underestimation of the emissions from storage vessels associated with that well. Thus, according to the commenter, at least 45 days is needed to evaluate and accurately calculate projected annual e missions from a storage vessel, and a nother 45 days would be needed to engage a contractor and install the necessary controls. The commenter provides that allowing a total of 90 days to make the initial emissions determination and install any necessary controls will ensure a more reliable emissions estimate and afford the regulated community sufficient time to contract for the testing/modeling of emissions and installation of controls.

The commenter (4626) request s that, i f the EPA does not differentiate between storage vessels at new and existing facilities, the EPA institute an extended compliance period for9

vessels at new facilities. According to the commenter, a n extended compliance period for vessels

at new fa cilities for a period of 2 years will reduce the likelihood that independent producers will be exposed to enforcement due to the lack of available equipment and service providers, while continuing to ensure that emissions reductions occur in a timely fashi on.

Another commenter ( 4631 ) recommends that the rule be revised to allow up to 120 days from startup to make the annual storage vessel VOC emissions determination. The commenter states that the additional time will allow operators to better understand an d predict the well decline and more accurately predict annual storage vessel VOC emissions thereby avoiding situations where unnecessary controls are required on new storage vessels. The commenter states that, during this period, the requirement to minimiz e emissions would still apply and should

annual VOC emissions exceed 6 tpy , controls will be required to be in place no later than 150 days from startup. The commenter states that, in the proposed rule under § 60.5395(c), the EPA has allowed 30 days followi ng startup to determine the VOC emission rate from Group 2 storage vessels. The commenter reports that, during the initial production phase of a well, liquid production levels are typically at their highest levels and then gradually decrease through a

rela tively brief (e.g., 30 to 180 day) decline period. Therefore, the commenter asserts that annual VOC emission estimates established during the first 30 days of production will likely exceed the actual observed annual VOC emissions for the storage vessels as sociated with the well when the liquids production decline curve is incorporated. The commenter is concerned that using initial, highest well production rates (i.e., first 30 days) rather than incorporating a representative decline curve into the storage v essel VOC emission estimate will lead to conservatively high VOC estimates that will result in the installation of unnecessary emission controls that would not be cost effective. According to the commenter, in accordance with proposed § 60.5395(d)(2), the

o wner or operator would need to wait a full 12 months before having the opportunity to remove such control devices when the uncontrolled storage vessel VOC emissions drop below 4 tons per year. The commenter states that installation of, and 12

- month operati on of, VOC control devices on storage vessels with actual annual VOC emissions of less than 6 tons per year would contribute to the cited shortage.

Another commenter (4617) requests that the EPA consider a longer timeframe to determine VOC emissions, and that they believed that 30 days may be too short. The commenter believes 60 days is a more appropriate time to understand emissions and recommends 90 days to install controls. According to the commenter, production rates and well characteristics are often not well understood until after 60 days of production. For example, the commenter reports that there could still be flowback fluids within this 30 day timeframe and inclement weather can

hinder the amount of data available to estimate emissions. The commen ter asserts that, requiring the evaluation of controls within 30 days could result in improper design of a control device and could lead to excess emissions from supplemental make

- up fuel or from the inability of the control device to handle a larger volum e of waste gas.

One commenter ( 4620 ) support s the extension of the 60

- day time frame for the design and installation of control devices to all storage vessels. However , the commenter believe s that a

90

- day period is more appropriate. The commenter reports that 90 days is required in order for many operators to evaluate emissions and install any necessary control device. According to the

commenter, p roduction and emissions data are often not available until up to 60 days after the10

date of first production a nd control device design. The commenter asserts that i nstallation can take months depending on the availability of controls. Additionally, the commenter reports that emissions evaluation and control design and installation schedules can vary between compan ies. Thus, the commenter believe s that requiring the emissions evaluation and control device installation within the 90 days provides for sufficient flexibility and maintains the real emission reductions required by the rule.

Response: The EPA does not ag ree with the commenters who variously requested that owners or operators be allowed 90 or 150 days or, for new facilities, 2 years to determine storage vessel emissions and install controls. Rather, the EPA continues to believe that a period of

30 days aft er startup is sufficient for an owner or operator to determine storage vessel emissions

and that an additional 30 days, for a total of 60 days after startup, is sufficient to install any necessary controls. The State of Wyoming already requires controls to be installed on storage

vessels within 60 days or less, depending on the location of the storage vessel and other factors, which we believe demonstrates that this is a workable time period. Accordingly, we have finalizing these requirements as proposed.

While we agree with the commenters who indicate that emissions typically decline and stabilize over time after startup, the EPA disagrees that this justifies delaying the determination of storage vessel emissions and the installation of controls. Rather, w e believe that it would be inappropriate to allow emissions to go uncontrolled for any longer than necessary during this period of highest emissions. As noted above, we believe that 60 days after startup is sufficient for owners or operators to determine e missions and install controls and, therefore, we believe that it would be inappropriate to allow more than 60 days.

In response to the commenters who recommended longer compliance deadlines (or alternatively requiring control only for “higher emitting st orage vessels”) due to concern about the availability of control equipment and service providers, we no longer believe that to be an

issue . See section IV.A of the preamble to the final amendments for a discussion of control device availability.

2.1.1.2 S upport for storage vessel affected facility definition

Comment: Several commenters (4613, 4615, 4617, 4620 , 4633 ) provide support for the

EPA’s amended storage vessel affected facility definition in §60.5365(e). Three of the commenters (4615, 4617, 4620) p rovide that they believe that the revised definition will decrease the administrative burden of the rule while ensuring low emissions rates.

One of the commenters (4613) asserts that, even though the 2012 NSPS requirement to control affected facility tank s contains a n emissions threshold and achieves the environmental benefits intended under this rule, the recordkeeping burden for all storage vessel affected facilities subject to the rule based solely on the 2012 final rule's proposal date (without the 6 t py emissions threshold) would be excessively burdensome.

Response: We acknowledge the commenters’ support and agree that the revised definition of “storage vessel affected facility” will reduce the administrative burden of the rule11

while maintaining the i ntended emissions reductions. See section IV. C of the preamble to the final amendments for more on the final affected facility definition for storage vessels.

2.1.1.3 Storage vessels whose emissions fall below 6 tpy and are required to remain affected faci lity should be limited to certain types of storage vessels

Comment: Two commenters (4615, 4630) state that the provision that a storage vessel that decreases emissions below 6 tpy VOC remains an affected facility should not apply to a storage vessel affect ed facility that is moved from one location to another. The commenters assert that it would be nearly impossible for the buyer of a used tank to determine whether the tank to be purchased was a “storage vessel affected facility” at its previous location, t hus effectively making all used storage vessels affected facilities. The commenters further state that because storage vessel potential emissions are site specific, the storage vessel potential to emit at a previous location is irrelevant to the new locati on.

Response: We disagree that a relocated storage vessel should no longer be considered an affected facility. However, we have added language at §60.5395(f) to address storage vessel affected facilities that are removed from service. Owners and operators are required to include a notification in their next annual report that the storage vessel has been taken out of service. If the storage vessel is subsequently returned to service due to fracking or refracking of a well feeding the storage vessel, then th e owner or operator must comply with the control requirements of §60.5395(d) immediately upon return to service. If, however, the storage vessel’s return to service in not associated with well fracturing or refracturing, the PTE of the storage vessel must be determined within 30 days. If the PTE is 4 tpy or greater, then the storage vessel affected facility must comply with control requirements within 60 days of returning to service. In either of these situations, the owner or operator is also required to i nclude a notification in their next annual report that the storage vessel has been returned to service.

See section V. B of the preamble to the final amendments for additional discussion of the provision that storage vessel affected facilities that decreas e emissions below 6 tpy VOC remain an affected facility.

2.1.1.4 Affected Storage Vessel Facility Custody Transfer

Comment: One commenter (4618) request s that storage vessel affected facility applicability be clarified to assist an owner or operator in de termining the applicability of the NSPS to a storage vessel after a custody transfer.

According to the commenter (4618), it appears the NSPS states that storage vessels downstream of the point of custody transfer are no longer subject to the rule. The com menter requests that the EPA confirm this interpretation, or clarify their intent as to how custody transfer affects the applicability of the NSPS to storage vessels. The commenter provides an example where multiple companies are involved with the handling of oil and gas products and the chain of custody includes a wellhead, a gathering station, and a processing plant: Company A owns the wellhead and transfers liquids offsite via pipeline to a gathering station owned by Company B. Company B sends the liquid s on to a processing plant owned by Company C. The commenter states that, in this example, their interpretation of the NSPS indicates that the NSPS appears only12

to apply to storage vessels operated by Company A, and would not apply to vessels at Companies B or C because those vessels are after the point of initial custody transfer.

Another commenter (4630) suggests that the term custody transfer not be limited to the transfer of natural gas. The commenter recommends that the definition of custody transfer be revised to encompass the transfer of liquid hydrocarbons as well. The commenter provides examples in paragraphs §60.5365(d)(1) and §60.5390(c)(1) where the phrase “the point of custody transfer to an oil pipeline,” is used, which implies transfer of liq uids. The commenter states that this phrase is also used in the preamble [78 FR 22133] to describe the boundaries of applicability for storage vessels. According to the commenter, since the EPA repeatedly uses the term custody transfer in a context that pe rtains to transfer of liquids, the definition should be revised to expressly denote that the term applies to the transfer of liquids as well as to the transfer of natural gas.

Commenter 4630 also states that the applicability should be specified to end at the point of custody transfer to an oil pipeline. The commenter believes that this would be consistent with §§60.5365(d)(1) and 60.5390(c)(1) for pneumatic controllers. In addition, the commenter suggests that the EPA add the phrase "or any other form of transportation" to §60.5360(e) to address scenarios in which the crude oil is transported from the production field by truck (or railcar, etc.). The commenter states that t his phrase comes from the NSPS s ubpart Kb definition of custody transfer and is used in the definition of custody transfer in this rule ( §60.5430 ) , but states that the definition in this rule is inexplicably limited to the transfer of natural gas.

Response: The EPA does not agree with the commenter’s example and conclusion that

storage v essels after the point of initial “custody transfer” (as interpreted by the commenter) through a pipeline at the wellhead would not be subject to the NSPS. This interpretation is apparently based on the EPA’s statement in the preamble to the proposed amend ments at 78 FR 22133 that “[i]t is our intent that the NSPS address VOC emissions from storage vessels located not only at wells but at any location from the well to the point of custody transfer to an oil pipeline or to the point of custody transfer from the natural gas transmission and storage segment to the local distribution company.” However, we note that the governing language from the 2012 NSPS, unchanged by these amendments, is found in §60.5365(e) where the storage vessel affected facility is defin ed to include “a single storage vessel located in the oil and natural gas production segment, natural gas processing segment or natural gas transmission and storage segment” with no mention of custody transfer. The statement in the preamble to the proposed amendments was intended to further illustrate the affected facility description in §60.5365(e). Based on the examples provided by the commenter, it is clear that the preamble illustration lends itself to misinterpretation. In any case, the language in §60 .5365(e) is correct, and thus storage vessels located outside the oil and natural gas production, natural gas processing and natural gas transmission and storage segments would not be subject to subpart OOOO.

We are not making any changes to the final ame ndments at this time in response to this

comment because of the reasons stated above and also because the term “custody transfer” is used in other sections of the 2012 NSPS not affected by these final amendments. However, w e continue to evaluate these comm ents for consider ation in our subsequent rulemaking to be completed by the end of 2014.13

2.1.2 Storage Vessel Applicability Determination

2.1.2.1 Definition of Storage Vessel

Comment: S everal commenters (4613, 4623, 4624) support the EPA’s proposal to rev ise the definition of “storage vessel” as being limited to those “vessels that contain crude oil,
condensate, int e rmediate hydrocarbon liquids, or produced water.”

Response: We acknowledge the commenters’ support and have finalized the proposed changes t o the definition.

Comment: One commenter (4633) requests that the final rule language for the definition of storage vessel in §60.5430 read as follows: "a tank or other vessel that is designed to contain an accumulation of crude oil, condensate, intermedi ate hydrocarbon liquids or produced water and that is constructed primarily of nonearthen materials (such as wood, concrete, steel, fiberglass, or plastic) which provide structural support."

Response: We do not agree with the commenter’s suggested change to the proposed definition and have not incorporated it into the final definition. In addition to creating potential enforcement complications, w e believe that including storage vessels that were “designed for” storage of the listed liquids could potential ly bring storage vessels under the NSPS that are not, in practice, used to store the listed liquids. This is not the intent of the amendments.

2.1.2.2 Group 1 and Group 2 Storage Vessel Determination

Comment: One commenter (4630) requests that the EPA mod ify the requirement for identifying storage vessels that come into applicability during the reporting period as being tied to startup of the affected facility and not when the storage vessel is constructed

, modified or reconstructed during the reporting pe riod. The commenter requests that paragraph §60.5420(b)(6)(i) be edited to reference the date of startup for an affected facility, rather than the date upon which construction, reconstruction, or modification commences. According to the commenter, the init ial annual report, which is due 90 days after the end of the initial reporting period, is to include documentation of the potential VOC emission rate (which is to be determined within 30 days after startup) as well as a statement that compliance with the s tandard has been achieved (which is to be achieved within 60 days after startup). In that the information to be reported is tied to due dates after startup, the commenter maintains that this provision for determining which storage vessels are to be include d in a reporting period should also be tied to

startup.

Two commenters (4613, 4620) request clarification on the definition of "construction" for storage vessels. Specifically, the commenters seek clarification of the EPA's intent with regards

to the use of the terms "constructed, modified or reconstructed" between specified dates and not premised with the word "commence" in §§60.5395 and 60.5430. The commenters also request that construction be triggered with "on

- site fabrication, installation or erection " of the vessel per the "construction" definition in 40 CFR part 52.21. The commenters state that if the EPA interprets the rule to include "commence" and for construction to be triggered when the contract is entered into to procure a vessel that the EPA a llow either definition discussed because the "on

-14

site fabrication, installation or erection" trigger is a more conservative option that would ultimately default more vessels into the rule. According to one commenter ( 4620 ) , these vessels are generally mass produced and it is common practice to have several vessels available in a storage yard awaiting installation at various facilities.

One commenter (4623) recommends that the EPA define Group 1 and Group 2 vessels in

relation to the date that construction commences. The commenter states that the proposed §60.5430 defines Group 1 and Group 2 storage vessels as those “constructed, modified or reconstructed” as of certain dates. However, according to the commenter, §§60.5360 and 60.5365 state that the subpart applies to facilities that “commence construction, modification or reconstruction after [specified date].” The commenter provides that §§60.5360 and 60.5365 are in accordance with the EPA’s longstanding approach that its rules apply on the date when equipm ent has been ordered, even if actual construction has not begun. The commenter believes that the use of the phrase “constructed, modified or reconstructed,” without any qualification, to define Group 1 and Group 2 vessels could be read as treating some ves sels that commence construction prior to the Group 2 trigger date as Group 2 vessels. The commenter suggests that the EPA revise the definitions of Group 1 and 2 vessels to include a reference to commencement of construction. The commenter states that, if the EPA does not adopt a “commence construction” approach for delineating between Groups 1 and 2, the insertion of “commencement” would be needed at least with respect to the Group 1 definition because otherwise, the EPA would classify as Group 1 a vessel that commenced construction prior to the rule applicability date of August 23, 2011, but was “constructed” after that date. The commenter also suggests that the EPA clarify what it means to be “constructed, modified or reconstructed.”

Another commenter (4 611) requests that the rule require that emission rates for affected storage vessel facilities that are not located at well sites be determined prior to commencing

construction. According to the commenter, emission rates at production field facilities and natural gas processing plants are typically known at design time. The commenter reports that many of these facilities are classified as major stationary sources or major sources of criteria or HAP emissions. The commenter further reports that construction, modification or reconstruction of an affected storage vessel facility at these larger facilities may trigger additional requirements unless they are permitted appropriately in a permit issued prior to construction.

Response: The EPA did not intend to dep art from the CAA and Part 60 General

Provisions definitions governing applicability based on the commencement of construction, reconstruction or modification. It was an oversight on our part to refer in the proposed amendments to the dates of construction, reconstruction or modification, rather than the dates that those activities commenced. Accordingly, the final amendments have been revised to include the commencement of construction, reconstruction or modification as the trigger point in the annual repor ting requirements for storage vessels at §60.5420(b)(6)(i) and the definitions of Group 1 and Group 2 storage vessels at §60.5430. The references to these activities that were included in proposed §60.5395 were not finalized as part of revisions for other purposes.

The EPA’s intention to conform to CAA and Part 60 General Provisions usage in this rule is clear from the language in §§60.5360 and 60.5365 of the 2012 NSPS, which is unchanged by the final amendments:15

§60.5360 What is the purpose of this subpa rt? This subpart establishes emission standards and compliance schedules for the control of volatile organic compounds (VOC) and sulfur dioxide (SO 2 ) emissions from affected facilities that commence construction, modification or reconstruction after August 23, 2011.

§60.5365 Am I subject to this subpart? You are subject to the applicable provisions of this subpart if you are the owner or operator of one or more of the onshore affected facilities listed in paragraphs (a) through (g) of

this section for whi ch you commence construction, modification or reconstruction after August 23, 2011.

However, in drafting the proposed amendments, we unintentionally left out the established concept that requirements are triggered based on the date that construction,

mod ification or reconstruction commences . We have corrected this oversight in the final

amendments.

Regarding the appropriate interpretation of the terms “construction” and “commence,” we rely on the NSPS General Provisions and NSPS program precedent. The NS PS General Provisions at §60.2 define these terms as follows:

Construction means fabrication, erection, or installation of an affected facility.

Commenced means, with respect to the definition of new source in section 111(a)(2) of the Act, that an owner or operator has undertaken a continuous program of construction or modification or that an owner or operator has entered into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of construction or modification

.

We do not believe that it is necessary here to elaborate on the application of these terms to storage vessels under this subpart. Implementing agencies have a wealth of experience in addressing applicability issues, and we are confident in their ability to apply these terms appropriately.

The EPA disagrees with the comment suggesting that applicability during the reporting period be tied to startup of the affected facility rather than when the storage vessel is

constructed/modified/reconstructed

. Under CAA section 111 (a)(2) and EPA’s General

Provisions in 40 CFR part 60, NSPS applicability is based on the commencement date of construction, modification or reconstruction, not start

- up date

.

Regarding the suggestion that the “construction” definition in 40 CFR 52.21 be applied to storage vessels under this subpart, we disagree. The NSPS program is well established with a long implementation history based on CAA section 111 and the implementing regulations in

40 CFR part 60 , which has long standing definit ions for the statutory term s “commence ” and

“construction

. ” The commenter has not distinguished storage vessels from other NSPS affected sources or otherwise explain why storage vessels should be afforded different definitions for these statutory terms.16

We also disagree with the suggestion that the rule should require that emission rates for affected storage vessel facilities that are not located at well sites be determined prior to commencing construction. While we agree that it may be possible to dete rmine emission rates at some facilities downstream from the well site prior to startup, we believe that it would be extremely difficult to define the cut point for such a distinction in a way that would be both clear and universally applicable. To maintain simplicity and consistency and avoid introducing uncertainty into determining the applicable requirements, we have finalized the amendments without creating the suggested differentiation among storage vessels. We do not believe that the requirements for p reconstruction permitting of storage vessels bear on the structure of the final

amendments.

Comment: One commenter (4630) requests that the EPA make changes to the definitions for Group 1 and Group 2 storage vessels. The commenter states that consistency with § § 60.5360

and 60.5365, the definition of Group 1 storage vessel should read “after August 23, 2011,” rather than “on or after August 23, 2011,” and should stipulate that the trigger is the commencement of
construction, modification or reconstruction. The commenter explains that determination of whether a storage vessel is potentially subject to the rule is based on the date upon which construction, modification or reconstruction commences, but determination of when the initial report is due for that s torage vessel is based on the date of startup. The commenter requests that a similar clarification be made in the definition of Group 2 storage vessel.

Response: We agree with the commenter that the definition of “Group 1 storage vessel”

should read “afte r August 23, 2011,” rather than “on or after August 23, 2011,” consistent with §§60.5360 and 60.5365. As discussed in the previous response, we also agree that the definition should stipulate that the trigger is the commencement of construction, modificati on or reconstruction. Accordingly, we have finalized the definitions of both “Group 1 storage vessel” and “Group 2 storage vessel” to reflect these considerations. Also as discussed in the previous response, we have declined to revise the amendments to bas e the determination of when the initial report is due for a storage vessel on the date of startup.

2.1.2.3 Group 1 and Group 2 Control Requirement Determination

Comment : One commenter (4626) expresses c oncern about the enforcement

ramifications of inaccur ately estimating annual emissions based on the first 30 days of production. According to the commenter, b ecause of inherent uncertainty in projecting the production of a given well, there should be provisions included in the regulations that provide

reduce d enforcement exposure if producers diligently monitor their throughput (and hence their emissions) and promptly report any errors discovered with regard to the annual emissions

estimate. The commenter recommends that the EPA include in the final version o f this rule provisions that provide operators reduced enforcement exposure if errors in annual production based emissions calculations are promptly reported (e.g., within 30 days) to the EPA (or the implementing state/local authority) and appropriate contr ols are installed within an additional 30 days. The commenter provides that, s uch notification would require an explanation of why the

initial annual emissions estimate was incorrect.17

Response: We expect owners and operators to exercise care in estimatin g storage vessel emissions, and we believe that the available methods for estimating emissions are reliable. Consequently, we do not believe that it is necessary to include provisions in the final

amendments to address situations in which the estimates are so flawed as to result in an incorrect determination of whether a storage vessel is an affected facility. We note also that we anticipate

that implementing agencies will exercise judgment according to their own procedures and experience in what should be rare circumstances where the initial applicability determination is

incorrect.

Comment : Two commenters ( 4621 , 4632) request that the EPA adopt a rolling monthly average of VOC emissions over 12 months (which would encompass a complete climatic cycle)

for an operator to determine whether a Group 2 or modified Group 1 storage vessel require

controls. The commenters believe that the current approach poses a problem for small producers. The commenters report that, i n the earliest months of well production, a s torage vessel will have an initial throughput that, if annualized, would result in estimated VOC emissions rate in excess of 6 tpy. However, the commenters provide that, over time, production will decline. The commenters opine that a far more accurate esti mation of annual VOC emissions can be determined once production l evels off. According to the commenters , however, that would not

occur within the 30

- day period the proposed amendments grant for making an initial estimation

of VOC emissions.

Response: We do not agree that the applicability of control requirements should be based on a full year of production data and have not revised this provision as requested by the commenters. We agree that production and emissions typically are highest in the earliest months of well production and will decline over time. For this reason, we believe it is important to install controls as quickly as possible so that storage vessels will not go uncontrolled at the very time that their emissions are the greatest. However, t o address the situation of declining production and emissions, the final amendments include an alternative emission standard in §60.5395(d)(2). Under this provision, a storage vessel affected facility can meet the alternative standard by maintaining uncont rolled actual emissions below 4 tpy after documenting uncontrolled emissions

below this level monthly for 12 consecutive months . Thus, affected storage vessels with significantly declining throughput and emissions may remove a control device that was initi ally required based on the level of emissions immediately after startup.

Comment : One commenter (4630) requests that the EPA specify that the potential VOC

emission rate shall be based on a 30

- day period of production prior to the date upon which the

dete rmination of the potential VOC emission rate is due. The commenter states that the potential for storage vessel emissions in the oil and gas production segment is driven by the potential throughput of produced fluids into the storage vessel. According to t he commenter, b ecause (as

the EPA acknowledged in the preamble at 78 FR 22129) all wells experience a decline in production over time, and the storage vessels associated with those wells experience a corresponding decline in throughput

. I t would be conserv ative, then, to base the potential VOC emission rate on the actual throughput experienced during the period of production immediately prior to the determination of the potential VOC emission rate being due, in that production throughput will decline therea fter. Thus, according to the commenter, the period on which this determination is based should be a representative 30

- day period of production prior to the date18

upon which the determination of the potential VOC emission rate is due. Given that the future

p otential for VOC emissions is practically limited by the actual throughput during the initial 30

- day period, the commenter requests that the rule specify that the potential VOC emission rate, upon which applicability is determined based on the 6 tpy thresh old, is to be calculated using any generally accepted model or calculation methodology applied to the average throughput rate determined for the representative 30

- day period of production.

Response: We believe that it is important that the applicability d etermination reflect realistically the storage vessel’s potential to emit VOC to ensure that control is applied to the appropriate storage vessels. Accordingly, we believe that the estimate of potential VOC

emissions should be determined based on maximum e missions during the 30

- day period rather than average emissions over that period. In the final amendments, we have revised §60.5365(e)

to require that the potential emissions determination be based on the maximum daily throughput of the storage vessel duri ng the 30 days immediately preceding the determination.

2.1.2.4 Date That Owners and Operators Must Begin Tracking “ E vent s ” From Group 1 Storage

V essels

Comment : One commenter ( 4613 ) requests that events that may increase emissions from a storage vessel b e considered only after the Group 1 and Group 2 control device installation date of April 15, 2014. The commenter opines that the assessment of "event" triggers after April 12, 2013 will most likely require retroactive determinations of potentially trigger ing events, especially since April 12, 2013

, has already past and further, because the proposed rule is not expected to be finalized until July 31, 2013. The commenter believes that this retroactive determination is infeasible and will create unnecessary a dministrative burden for tracking of all Group 1 tanks to assess if the "event" occurred, based on different timeframes than the rest of

affected faciliti es considered as Group 2 tanks.

T wo of the commenters (4615, 4630) state that the date upon which the owner or operator must begin to track these triggering events should allow time for initial determination of the potential VOC emission rate. The commenter s provide that the EPA’s proposed language specifies that the owner/operator must begin to track eve nts on April 12, 2013, but determination of which storage vessels are subject to this requirement is not due until October 15, 2013. According to the commenter s , it is unreasonable to require events to be tracked before it is even known for which storage v essels the requirement is applicable. The commenter s opine that the date for beginning the tracking of these events should be no earlier than October 15, 2013

, the date upon which determi nation of applicability is due.

According to one commenter ( 4615 ) , s ince compliance with the proposed rule applies at all times, an operator needs the minimum of 60 days proposed in the rule to obtain and install control equipment after an event has increased emissions from a Group 1 storage vessel. The

commenter suggests that a minimum of 90 days is needed to implement controls and that 90 days would be more appropriate due to the need to size, order, and install the controls.

Similarly, another commenter (4612) submits that it is appropriate to allow for 60 days

for the application of controls. According to the commenter, while some changes that can increase emissions are planned in advance, emissions calculations cannot be performed by19

midstream facilities until the production levels for a new well have been established in order to accurately determine whether controls will be needed. In addition, the commenter states that midstream facilities will have different engineering requirements than production sites. The commenter reports that, if there is an emissions increase, equipment will have to be designed, obtained, and installed, which takes even more time. The commenter asserts that some facilities may also need to comply with OSHA Process Safety Management (PSM) requirements after installing controls. The OSHA PSM requ irements include the need to conduct a process hazard analysis where operating procedures must be put in place, and operating staff trained, to run the required processes before startup. The commenter states that a period of 60 days to accomplish

these tas ks is barely sufficient, even if the emissions increase is the result of a planned change.

One commenter (4623) argues that the EPA should tie potential triggering of Group 2 controls to the promulgatio n date of the revisions of the reconsideration propos al

. According to the commenter, the EPA’s proposal that operators track such events that occur on or after April
12, 2013

, is unworkable because operators were unaware of this requirement on that date. The commenter opines that it would likely be difficult or impossible for operators to identify events and any associated “change” in emissions when they were not required to keep records of these

past occurrences.

Response: In the final amendments, we are not finalizing the proposed requirement to

track eve nts for Group 1 storage vessels (refer to section I V. A of the final rule preamble for further discussion regarding these changes). Therefore, the concern expressed by the commenter

is now moot.

2.1.2.5 Storage Vessels That Initially Have PTE Less Than 6 t py

Comment: Two commenters state that the final rule should specify a compliance period for Group 2 storage vessels that originally had potential VOC emissions less than 6 tpy and subsequently experience an event that causes the potential VOC emission ra te to meet or exceed 6 tpy. In such cases, the commenters request that the storage vessel should be required to achieve compliance within 60 days after the event.

Another commenter states that the proposed amendments do not limit the Group 2 control trig ger to planned events and may include unplanned events such as emergency well reroutes as well as “any other” event that could increase VOC emissions. According to the commenter an operator cannot control and plan for an emergency event such as a tank fail ure that forces the re

routing of a well to a nearby vessel, nor for an unspecified “other” event.

Response: The proposed amendments clearly specify when compliance must be achieved for Group 2 affected facilities. We have finalized this compliance date, as proposed. Concerning the comments about “events” that increase the VOC PTE of a Group 2 storage vessel, the commenter is correct that initially we failed to address the issue of storage vessels that, during their initial evaluation, have PTE less than 6 tpy and are not determined to be affected facilities but that subsequently increase emissions such that PTE is 6 tpy or more. We agree this is a problem. Although our proposed rule did not include measures for us to finalize today to address this issue, we continue to evaluate this issue and intend to complete this20

evaluation in conjunction with our consideration of other issues that we plan to finalize by the

end of 2014.

2.1.2

. 5 “Frac Tanks” Used As Temporary Storage

Comment: Several commenter s ( 4613, 4617, 4620) request that the EPA confirm that "frac tanks" used as temporary storage during the flowback period are not considered storage vessels as defined in §60.5430 and may be used to transport or store flowback fluids in compliance with §60.5375(a). T he commenters (4613, 4620) state that, if the EPA did intend to regulate these containers under the storage vessel standard, that they confirm that “frac tanks”

on

- site for less than 180 days or that are used in the process of recycling and transporting l iquids, are categorized as temporary or process vessels, respectively.

The commenters (4613, 4617, 4620) provide that the EPA indicated in the preamble to the original rule and to the proposed revisions that the intent was to regulate “[c]rude oil,

cond ensate and produced water [that] are typically stored in fixed

- roof storage vessels.” 76 FR 52763. They report that the EPA further stated that the “intent was to regulate only certain storage vessels (i.e., those storage vessels that may likely emit VOC e missions), not every

container.” 78 FR 22132. According to the commenters, h ydraulic fracturing tanks are generally neither fixed roof nor likely to emit signifi cant amounts of VOC emissions. The commenters explain that fluids that flow through these tanks are often reused or recycled and are cycled through on a semi

- continuous basis that is inherent to the flowback and fracturing process. Further, according to the commenters, when these containers are used to actually store fluids, the tanks are rarely on

- site for more than 180 days.

Response: The commenters state that hydraulic fracturing tanks are likely to have low emissions. If this is the case, then they likely would not be an affected facility (i.e., potential to emit VOC of 6 tpy or more). If the po tential VOC emissions from the hydraulic fracturing tank

are at least 6 tpy, then they would be considered a storage vessel affected facility and would be subject to the storage vessel requirements under the final amendments. As mentioned by the

commenters

, the definition of storage vessel in §60.5430 of the proposed amendments includes a provision that storage vessels located at the site less than 180 days are not considered to be storage vessels. We point out that §60.5430 also specifies that the storage vessel must be skid

mounted or permanently attached to something that is mobile to qualify for this exemption. I f the fracturing tanks were to satisfy all these exemption criteria, they would not fit the definition of “storage vessel” and would, therefore, not be considered storage vessel affected facilities. Concerning process vessels, the storage vessel definition provides examples of process vessels that include surge control vessels, bottoms receivers and knockout vessels. The vessel in question would n eed to have a similar use to be considered a process vessel.

2.1.2.6 Storage vessel affected f acility definition

Legally and Practically Enforceable Limits

Comment : One commenter (4612) supports the proposal to clarify the type of storage

vessel that woul d be subject to the Oil and Gas NSPS: storage vessels considered to be affected

facilities would be those that have VOC emissions of 6 or more tpy and are used to store crude oil, condensate, unrefined petroleum liquids, and produced water. The commenter a lso supports21

the proposed clarification that a source can take into account any legally and practically enforceable emission limit when determining the VOC emission rate for purposes of calculating

threshold emissions. The commenter asserts that the 2012 N SPS could have been read to apply to storage vessels containing any sort of material. In addition, prior to the EPA proposed

amendments , the final rules contained inconsistent and incomplete provisions regarding the 6 tpy VOC applicability threshold. The c ommenter also agrees that it is appropriate to take enforceable limits into account in determining whether a storage vessel is subject to the Oil and Gas NSPS.

Response: We acknowledge the commenters’ support and have finalized the proposed

amendments to the storage vessel affected facility definition. Section IV.C of the preamble to the

final amendments discusses other changes we made to the storage vessel affected facility

definition.

Comment : One commenter (4623) believes that the EPA has proposed ap propriately that legally and practically enforceable limits on emissions would be considered in determining potential emissions for purposes of NSPS applicability

. H owever, according to the commenter, the phrasing of this provision is somewhat ambiguous an d cumbers ome. The commenter believes that, by the EPA stating that it would take “into account requirements under a legally and practically enforceable limit in an operati ng permit or by other mechanism,” and that i t is unclear

what the distinction is betw een “requirements” and a “legally and practically enforceable limit .”

The commenter suggests that the l anguage should read “taking into account legally and practically enforceable limitations on the potential to emit.” The commenter also states that i t is unclear what the purpose of specifically mentioning operating permits is when, often such limits are established by construction permits or may apply by virtue of a categorical regulation in the state implementation plan (SIP) or in a state regulation that is not a part of the SIP. The commenter requests that the EPA clarify, at least in the preamble, that construction permits, state rules, and the like are acceptable methods of satisfying that emissions are below the threshold.

Response: In response to th is and other comments, we have revised §60.5365(e) in the

final amendments to clarify the storage vessel affected facility definition. Refer to section IV. C of the preamble to the final amendments for further discussion.

Applicability Emissions Rate Deter mination

Comment : One commenter (4611) requests that the EPA ensure that both flash and working/breathing losses are counted towards the 6

- tpy threshold and that all components of VOC emissions be included in the calculation. The commenter provides that not all generally accepted models or calculation methodologies are capable of calculating both flash and working/breathing losses.

Response: All of the generally accepted models of which we are aware account for working and breathing losses in addition t o flash emissions.

Comment : One commenter (4623) suggests that the EPA include a clarification in the regulation of how to determine the emissions rate for the 6 tpy threshold. The commenter opines

that the EPA should clarify that it intends the potentia l to emit analysis to represent a reasonable22

calculation of the emissions from the vessel based on the production estimates of wells that are connected to that particular vessel.

Response: We have revised §60.5365(e) in the final amendments to more clearl y specify how the potential emissions are to be determined. We believe these revisions address the

commenter’s concerns. Section 2.1.2.3 of this document presents further discussion of this issue.

Comment: One commenter (4630) states that, as subpart OOOO is currently structured, it is not clear that a storage vessel subject only to a requirement for at least 95 percent control could rely on this control requirement to create a legally and practically enforceable limit on VOC emissions below 6 tpy. Accordi ng to the commenter, it would provide a more straightforward compliance pathway than determining PTE considering legally and practicably enforceable controls. The commenter believes that this approach is appropriate in the context of the unique nature of o il and gas production and of the differing state regulatory regimes for oil and gas production as opposed to industrial sites.

The commenter (4630) asserts that many state programs do not currently have VOC mass emissions limits for storage vessels or eff ective means of obtaining permits that contain them. Likewise, according to the commenter, these programs may not have effective means of imposing operational limitations that could be coupled with a percent control requirement, or may not have extensive m onitoring and recordkeeping obligations. The commenter maintains that this would mean that many storage vessels could be viewed as not having a legally and practically enforceable limit of less than 6 tpy, even though their emissions are much less than

tha t level because of the installation of a control device or routing to a flow line.

The commenter (4630) suggests changes to §§60.5365(e) and 60.5395(c) that are designed to streamline the process for determining PTE for VOCs from storage vessels and avoid potential problems with state programs that impose control requirements, but not specific VOC emissions limits or operational limitations. The suggested changes include: (1) u sing the first thirty days of production in a model to define PTE from a storage vessel; (2) c onsolidating provisions on determining VOC PTE in §60.5395(c) for clarity and consistency; (3) c larifying that emissions controls required by applicable state regulations or guidance can be used to determine the VOC potential of a storage ves sel, and (4) c learly defining what emissions must be considered in the calculation of the potential VOC emission rate.

The commenter (4630) states that the term potential to emit is not defined in subpart OOOO or 40 CFR 60.2. According to the commenter, r elatively few storage vessels will be in states that have the type of limitation that would act as an acceptable limitation on PTE. The commenter explains that this means that the operator of a subpart OOOO storage vessel would

have to determine emissions based on the maximum capacity of that storage vessel to emit a pollutant, which could significantly raise the emissions from a storage vessel, particularly for wells with significant decline factors.

The commenter (4630) also states that they do not belie ve that the EPA intended the use of maximum design capacity in determining VOC emissions potential, since §60.5395(e) provides for the use of “any generally accepted model or calculation methodology,” which will23

generally rely on established production rat es and flash emissions estimates, rather than worst case assumptions. Indeed, according to the commenter, the unique nature of oil and gas production means that maximum design does not truly reflect the PTE, given natural reservoirs with less predictable f

low, increases and decreases in flow over time, and inability to ramp production up and down to take advantage of equipment sizing and demand.

According to the commenter (4630), their proposed changes would help maximize the flexibility for state NSR and SIP programs so that storage vessel emissions can be reduced through legally and practically enforceable means to minimize the impacts to agencies and the regulated industry, while achieving the EPA’s emission reduction goals.

Response: We have revised §6 0.5365(e) i n the final amendments to more clearly specify how the potential emissions are to be determined. In particular, we have revised §60.5365(e) to state that the potential emissions determination must be based on the maximum daily throughput

of the storage vessel during the 30 days immediately preceding the determination.

Depending on the baseline emission, a 95 percent control requirement does not necessarily result in below 6 tpy VOC emissions. Therefore, one cannot rely on such limit alone

to ens ure the PTE remains below 6 tpy. In response to the commenter’s concern about the ability of state programs to issue permits with the necessary limits to ensure the PTE remains below 6 tpy, these concerns are beyond the scope of this action and are not add ressed here.

Comment: One commenter (4615) com m ented on EPA’s solicitation for comment on distinguishing characteristics between this NSPS and other EPA regulations warrant an approach where, if an emission limitation is equivalent to the NSPS emission s tandards and can be enforced by state or another federal requirement, compliance with the NSPS should not be

necessary ; oversight concerns of such an approach, and how such approach is permissible under

CAA section 111 . The commenter opines that such an ap proach is permissible under CAA section 111 and is needed to prevent duplicate regulation from an NSPS rule and from state, tribal, or local air permits or BACT requirements.

Response: The commenter provides no additional information for us to evaluate th e questions we posed in our solicitation for comment.

VOC Emission Threshold for Storage Vessels

Comment : Two commenter s (4621 , 4632) opine that, based on the EPA’s technical modeling, the EPA should accept an operator’s determination that a storage ves sel won’t require emission controls if the throughput is less than 20 bbl/day. The commenter s assert that the requirement that Group 1 wells (those constructed, modified or reconstructed after August 23,

2011

, and on or before April 12, 2013) provide initi al notification to the EPA by October 15,

2013

, raises a significant issue for small producers: How does a producer determine whethe r a storage vessel exceeds 6 tpy ? According to the commenter s , complicating this matter is the fact that the EPA has not giv en guidance on recommended methods for determining VOC emissions.

The commenter s provide that they understand why the EPA moved away from the throughput threshold of 20 bbl/day to the 6 tpy potential VOC emissions threshold. However, they believe24

that thro ughput is the simplest and clearest methodology for an operator to determine if controls are required.

Another commenter (4623) recommends that the EPA increase the storage vessel VOC threshold to 12 tpy based on cost effectiveness of controls at that lev el

. According to the commenter, the f

inal rule definition fails to include an applicability threshold for VOCs. The commenter asserts that, although the final rule requires controls only for those vessels with a PTE of greater than 6 tpy, this affected fac ility definition could be interpreted as including all vessels regardless of VOC emission levels. The commenter opines that such an interpretation would mean that notification, recordkeeping, and reporting requirements would apply to all storage vessels, e ven if they have very low VOC emissions. Thus, the commenter supports including an applicability threshold but recommends that it be set at 12 tpy, not 6 tpy based on

the costs of controls for enclosed combustors that the EPA calculated in its Air Pollutio n Control

Cost Manual. The commenter believes that 12 tpy is the lowest threshold that reduces emissions

at a cost

- effective level.

Response: We previously rejected a throughput threshold in the 2012 NSPS because we concluded that it is not a good indica tor of VOC emissions due to the high variability in volatile content of the liquids flowing through storage vessels at well site and other para m eters affecting

emissions (77 FR at 49500, 49524). Nothing in the comment changes this conclusion.

We also dis agree that the threshold should be increased to 12 tpy. As discussed in the preamble to the 2012 NSPS (77 FR 49524), we determined that 95 percent control of storage

vessels at 6 tpy or more is cost effective

.

Concerning the comment that we did not provi de guidance on methods to determine VOC emissions from storage vessels, we point out that in the Response to Public Comments document on the August 23, 2011, proposed rule (see p. 126 of the document) , which is available in the docket, several tools for ca lculating emissions were listed by commenters . These tools included computer programs such as E&P TANKS, HYSIM, HYSIS, WINSIM, PROSIM, as well as calculation methodologies such as the Vasquez

- Beggs equation.

2.1.2.7 Clarification of Requirements for Deter mining Group 1 Storage Vessels VOC Emissions

Comment: One commenter (4633) seeks clarification that changes in flow between individual storage vessels at centralized batteries or at locations with multiple tanks does not trigger a change from Group 1 to G roup 2 status. The commenter states that the proposed requirements separating storage vessel affected facilities into two groups, "Group 1" and "Group 2," include a review of changes made after April 12, 2013 at "Group 1" tanks to determine if the change " could reasonably be expected to increase VOC emissions." According to the commenter, while reviews of single

- well pads would be straightforward, complications could arise for reviews involving the operation of storage vessels at multiple

- well pads or centr alized tank batteries. In centralized batteries, for example, a number of centralized tanks receive flow from numerous wells. The commenter reports that, typically, the production from each well can be routed to any of the storage vessels based on operatio nal needs. The commenter expresses concern regarding the language in §60.5395(b)(iv) stating "any other event that could increase the VOC emissions from the storage vessel affected facility." The commenter explains that the25

overall tank battery's VOC emiss ions would not change if flow is moved from one tank to another, but the emissions from each tank could change as a result. The commenter requests that the EPA provide a definition of what constitutes a "change" and/or an "event" that could reasonably be e xpected to increase VOC emissions.

Response: In the final amendments, we are not finalizing the requirement we had proposed to track events for Group 1 storage vessels (refer to section IV.A of the preamble to the

final amendments for further discussion r egarding these changes). Therefore, the concern s expressed by the commenter are now moot. We point out, however, that the commenter’s belief that a storage vessel could change from Group1 to Group 2 is incorrect. Whether a storage vessel

is classified as G roup 1 or Group 2 is determined solely by the date on which construction, modification or reconstruction was commenced for the storage vessel, as defined in §60.5430.

Comment: Two commenters (4623, 4630) requested that the EPA allow owners and

operators t o opt into the more stringent Group 2 control requirements for Group 1 storage vessels and avoid the need for tracking “events.” Specifically, one of the commenters (4623) requests that the EPA provide a mechanism for Group 1 vessels to voluntarily subject themselves to the Group 2 requirements upon installation of a control device and opt

- out of the requirement to

track “events.”

Response: We are not finalizing the proposed requirement to track events

, and the final rule requires Group 1 storage vessels t o meet the control requirements by April 15, 2015. Therefore, the concerns expressed by the commenters regarding tracking events are now moot.
Refer to section IV.A of the preamble to the final amendments for further discussion regarding these changes.

2. 1.2.8 Emergency and Safety Exceptions

Comment : Four commenters ( 4615, 4620, 4623, 4630) request special provisions for storage vessels that are installed during emergency or safety situations. Some of these commenters (4615, 4623, 4630) suggest that the EP A include a 180

- day delay for designating

these storage vessel s as an affected facility

.

One commenter (4615) recommends that the EPA allow a 180 day window before a like

kind replacement storage vessel b ecomes an affected facility in s ubpart OOOO. Accord ing to the commenter, unless the EPA allows for a 180 day window, in some states, an operator would first need to obtain a construction permit or operating permit modification to install an emergency replacement vessel since it would be considered an NSPS affected facility.

Another commenter (4620) requests that the EPA clarify that storage vessels installed for the beneficial purpose of replacing existing vessels due to mechanical integrity or Spill Prevention Countermeasure and Control (SPCC) compliance purposes are not considered new or modified storage vessels under the rule. The commenter asserts that, in the case of this routine replacement activity there is no associated emissions increase, but significant risk reduction from a spill and safety persp ective.26

Another commenter (4623) requests that the EPA define and exclude “emergency replacement vessel(s)” from the rule for 180 days. The commenter asserts that the rule creates uncertainty for sources that must replace a storage vessel in cases of fail ure. According to the commenter, the rule could create potential permitting delays because many jurisdictions require a construction permit for replacement vessels if the vessel is subject to an NSPS. The commenter requests that the EPA provide the ability to extend the use of a temporary tank if the facility has applied for required permits for a permanent tank but has not had sufficient time to install it (recognizing that obtaining the permit may itself take 6 or more months and that construction on

the tank cannot begin until the permit is obtained). The commenter states that defining a term, emergency replacement vessel, as not subject to the NSPS would allow permanent replacement units to be installed without a minor NSR construction permit. According to the commenter, under their suggested scenario, this permit would be obtained within 180 days, when the emergency classification expires. The commenter asserts that this approach would address potential problems with temporary tanks in that they are typi cally rectangular and often do not fit into the existing containment berm for a round permanent storage vessel. Additionally, the commenter reports that temporary tanks may also require installation of temporary piping and, due to their size, multiple repl acement tanks may be required to temporarily replace one failed storage vessel. Lastly, according to the commenter, temporary tanks are generally not compatible with emission control devices, and thus may not be an option due to state permit requirements

f or control devices or emission limits.

One commenter (4630) requests that the EPA include a 180

- day delay for designating a new storage vessel as an affected facility when the activity qualifies as an emergency replacement. The commenter states that there is precedent for a 180

- day period in such cases already set by the EPA through allowed use of temporary storage vessels. The commenter further states that if a permanent storage vessel is brought in before expiration of the 180

- day period that

was started with a temporary storage vessel, the deadline for designating as an affected facility is not reset; whatever storage vessel is in place at the end of the 180

- day period becomes a storage vessel affected facility. According to the commenter, emergency repl acement of a storage vessel may be required for various reasons, including but not limited to storage vessel failure having been deemed imminent or having already occurred. According to the commenter, pri or to the promulgation of NSPS s ubpart OOOO, storage vessel replacement in the oil production segment often did not trigger any state permitting requirements. However, the commenter reports that several states require permits for any facility that becomes subject to an NSPS, in which case

installation of a r eplacement storage vessel as a s ubpart OOOO affected facility would not be allowed until it was permitted. The commenter states that for nonemergency storage vessel replacement, where advanced planning allows time for the permitting process, this is not a significant issue. However, according to the commenter, when an emergency replacement is needed, advanced planning time is minimal to nonexistent, and the permitting trigger becomes a major issue in that a replacement storage vessel is needed immediately but the state does not allow such replacement until a permit is obtained. The comme nter further states that while

s ubpart OOOO allows for a temporary storage vessel to not be an affected facility for up to 180 days in such cases, it would be preferable to immediately install a permanent replacement if one

is available.27

The commenter (4630) asserts that the solution to emergency replacement of storage vessels is to delay triggering the affected facility designation for 180 days from the start of

installatio n of the replacement

, regardless of whether the replacement is a temporary or permanent storage vessel. The commenter maintained that if an operator has a new permanent storage vessel immediately available to replace a failed storage vessel, replacement in stallation would then be allowed to begin while concurrently applying for the needed permit. Additionally, the commenter stated that replacement construction would need to occur only once if a permanent vessel could be used, thereby reducing costs for the operator.

The commenter (4630) requests that a new definition of "storage vessel emergency replacement" be added to clarify the usage of this term. This commenter also requests changes in the associated recordkeeping requirements to address their request ed delay change

.

Response: The EPA does not believe , nor have the commenter s offered any support, that

CAA section 111 authorizes delaying affected facility determination , which in turn would delay compliance

, to allow facilities to first deal with their state requirements. In fact, such delay would seem contrary to the requirement under s ection 111(e) of the CAA , which prohibi ts a ny new source from operating in violation of any applicable NSPS. We believe that state agencies,

not the EPA, are more appropr iate in addressing their own re quire ments.

We note , however, that the definition of storage vessel under §60.5430 includes a provision that “[v]essels that are skid

- mounted or permanently attached to something that is mobile (such as trucks, railcars, b arges or ships), and are intended to be located at a site for less than 180 consecutive days” are not considered storage vessels. The provision of 180 days, which was promulgated in the 2012 NSPS, would allow the owner or operator to bring in a temporary

r eplacement vessel that was skid

- mounted or was permanently attached to something mobile for up to 180 days until the permanent replacement tank could be obtained and the requisite permits

obtained. According to the comments, this 180

- day period would be su fficient to obtain the permits

.

2.1.2. 9 Alternative Emissions Standard

General Support and Opposition for 4 tpy Alternative Emission Standard

Comment : Several commenters (4612, 4613, 4633) support the concept of the provisions

for the removal of contro ls at such a time that production and associated emissions decline to below a control threshold, as described in §60.5395(d)(2).

One c ommenter ( 4612 ) reports that the claimed benefit of freeing up scarce control equipment where emissions have consistently been below the 6 tpy VOC applicability threshold in the Oil and Gas NSPS would be diminished by lowering the 4 tpy requirement in proposed § 60.5395(d)(2). The commenter states that t his is because fewer storage vessels could take advantage of the complian ce alternative if the 4 tpy limit were reduced, and therefore fewer storage vessels would be able to operate without control equipment. According to the commenter (4612), t here is no reason to require a storage vessel with demonstrated emissions of less th an 4 tpy VOC to continue to apply controls. If anything, the commenter believes that the EPA should revise proposed § 60.5395(d)(2) by raising t he 4 tpy limit to 5 tpy, because they believe it would28

free up additional control equipment while still limiting the availability of the no

- controls compliance alternative to those vessels whose VOC emissions are well below the 6 tpy applicability threshold.

Response: We acknowledge the commenters ’ support for the concept of the provisions

that would allow the remov al of controls where emissions have declined to below a specified

emission rate

. Please see section IV.A of the preamble to the final amendments for a discussion

on our revised estimate of the combustor supply and our rationales for finalizing an uncontrol led

actual VOC emission rate of less than 4 tpy.

Alternative Emission Threshold Periodic Emissions Determinations

Comment : One commenter (2624 ) supports monthly recordkeeping requirements to determine emissions and verify compliance with the alternative emission limit and states that the proposed requirements wou ld be consistent with standard t itle V reporting requirements

.

Another commenter (4626) states that, instead of requiring 12 months of data demonstrating un controlled emissions below 4 tpy, they believe that six months of data

dem onstrating emissions below 6 tpy is sufficient. The commenter also suggests that the obligation to conduct monthly monitoring be discontinued after six months of data demonst rating VOC emissions below 4 tpy , absent an in tervening ev ent as set forth in § 60.5395(b)(2).

One commenter (4612) states that the periodic emissions determinations should, at most, be required on a monthly basis because it would present an unnecess ary increased burden on

owners and operators if they had to make such determinations on a more frequent basis, with

little additional environmental benefit. The commenter a sserts that a rule that requires more frequent determinations would contravene the President's Executive Order 13563, which directs

fede ral agencies to "identify and use the best, most innovative, and least burdensome tools for achieving regulatory ends." In addition, according to the commenter, the proposed rules should be revised to provide that determinations need only be made on a quar terly basis once there had

been 12 consecutive months of VOC emissions less than 4 tpy after the removal of controls. According to the commenter, t his would be an appropriate lessening of the regulatory burden as it would only apply to storage vessels with a substantial history of consistently low VOC

emissions.

One commenter (4613) suggests that quarterly versus monthly calculations be allowed.

The commenter does not object to the requirement to demonstrate that the VOCs are below a

certain threshold for the time per iod of twelve consecutive months ; however, they feel that quarterly calculations would adequately demonstrate a well ’ s decline since production typically peaks early in the life of the well and declines rapidly. The commenter request s that the EPA allow quarterly de monstrations of VOC emissions f o r this provision, as opposed to monthly.

Similarly, another commenter (4630) requests that the EPA include a provision for emission calculations to be less frequent if the actual VOC emission rate pers ists at a level of less than 4 tpy. The com menter states that this would be similar to the reduced monitoring frequency specified in LDAR programs, where it would be appropriate to reduce the calculation frequency29

from monthly to quarterly after a period o f continued documentation that the actual VOC emission rate is being maintained at less than 4 tpy. According to the commenter, calculations to demonstrate compliance would be needed less frequently when the actual emission rate has been

demonstrated to be persistently below 4 tpy, and the reward of less frequent emission calculations would provide an incentive for owners and operators to achieve low emission rates

.

One commenter (4615) suggests that , after the first 12 consecutive months of less than 4

tp y uncontrolled VOC emissions, the frequency of determinations should revert to annual

determinations.

Response: We have finalized the proposed monthly recordkeeping requirements to determine emissions and verify compliance with the conditional uncontrol led actual VOC

emission rate in the final rule. We believe the monthly requirement is necessary to assure compliance with the less than 4 tpy uncontrolled actual VOC emission rate. Even though we acknowledge that there is generally a gradual decline in emi ssions over the life of a well, there may also be fluctuations in flow where emissions could potentially increase, requiring that we maintain monthly emissions determinations and recordkeeping requirements in order to prevent

uncontrolled emissions from re aching 4 tpy

. See section V.C of the preamble to the final

amendments for further discussion of this issue.

Clarification of Requirements After Emission Rates Decrease Below 4 tpy

Comment: One commenter (4630) requests that the EPA clarify that the use o f a control device may be discontinued when emissions fall below 4 tpy. The commenter states that the EPA's intent was to specify that if the uncontrolled VOC emission rate for a storage vessel affected facility that is subject to Group 2 controls subseque ntly drops below 4 tpy, the controls may be discontinued as long as the storage vessel is maintained at less than 4 tpy as documented by monthly calculations. The commenter cites the proposal preamble to illustrate the EPA's

intent ( 78 FR 22133 ) . The comme nter requests that the EPA revise the rule language to reflect

this intent.

Response: We are finalizing the alternative uncontrolled actual VOC emission rate of less than 4 tpy, as proposed

. Refer to section V.C of the preamble to the final amendments for

comments on the alternative uncontrolled actual VOC emission standard and the EPA’s responses to those comments.

Comment: One commenter (4630) recommends that the rule text clarify that, while remaining an affected facility, a storage vessel that has its potential for VOC emissions decrease to less than 6 tpy would become subject to the standard specified in §60.5395(d)(2), rather than that specified in §60.5395(d)(1), if the VOC emission rate were to fall below 4 tpy.

Response: We revised §60.5395(d) of the final rule to better clarify storage vessel applicability requirements (including requirements associated with the uncontrolled actual VOC

emission limit of 4 tpy). We believe that the revisions made address the commenter’s concerns.

See section V.C o f the preamble to the final amendments for a discussion of this issue.30

Clarif ication of Requirements for Group 1 Storage Vessels that Become Subject to

Control Requirements after an Event and Opt For the Alternative Emission Standard

Comment: One comment er (4623) requests that the EPA clarify and revise language concerning Group 1 vessels that become subject to the control requirements after an event that opt for the 4 tpy alternative mass

- based limit. According to the commenter, most Group 1

storage vess els, unless required by local regulations, will not have had a control device installed, nor have they been required to keep records of their actual VOC emissions for 12 months prior to triggering an event. The commenter believes that an absurd outcome tha t may result is that a Group 1 vessel with actual emissions, post

- event, of 3 tpy, may be required to install controls to achieve a 95 percent reduction for 12 months, after which time it may remove the controls. To avoid this outcome, the commenter reques ts that the EPA revise the criteria for meeting the 4 tpy limit to remove the control and recordkeeping requirements for any vessel transitioning from Group 1 to Group 2 due to an event.

Response: We believe the commenter is referring to the proposed requ irement that Group 1 storage vessel affected facilities would be subject to the control requirements only after an event that would likely increase emissions. We are not finalizing the proposed provisions

related to events

, so the commenter’s concern relat ive to that proposal is now moot. See section

IV.A of the preamble to the final amendments for a discussion of this issue.

Reinstallation of Controls If Emissions Increase Above 4 tpy

Comment : One commenter ( 4620 ) recommend s that the reinstallation of co ntrols be required within 90 days of the determining that projected actual or actual emissions are over 6

tpy. The commenter bel ieve s that it is more appropriate to require reinstallation at the same 6 tpy threshold applicable to new Group 2 storage vessel s or Group 1 vessel with a triggering event rather than the 4 tpy alternativ e emission limit. The commenter state s that these storage vessels will require the same installation and design requirements as the initial control device installation

and should h ave the same control threshold.

One commenter ( 4612 ), in response to the EPA’s concern about leaving em issions

unaddressed for a 30

- day period under this proposal (where emissions in excess of 4 tpy VOC may be uncontrolled for a short period of time, betw een the monthly emissions determination and the application of controls) is that a period of at least 30 days is appropriate for the

installation of controls in this circumstance. The commenter provides that application of controls

will often involve locat ing and acquiring the necessary equipment, installation, and testing, a process that can be expected to take weeks to complete. According to the commenter, shortening the deadline to a period less than 30 days would create a requirement that in many cases would be very difficult if not impossible to fulfill, with minimal environmental benefits in most cases. The commenter asserts that shortening the 30

- day period by a week or 10 days would not appreciably minimize emissions, which could be expected in many cases to be only slightly above the 4 tpy VOC uncontrolled emissions threshold allowed by the proposed revisions. According to the commenter, i t is unlikely that many storage vessels that had been operating so as to emit less than 4 tpy VOC would suddenly begin operating at a much higher level.31

Two commenters ( 4615 , 4630) provide that they believe the appropriate measures to take

for this short 30

- day period should be the same as it is for “new” affected storage vessels in §60.5395(c)(2) which is to “minim ize emissions to the extent practicable during the 30

- day period using good engineering practices through the period prior to installation of controls.” According to the commenter s , typically, it will take just as much time to obtain and reinstall

controls as it would for installing controls for a newly affected storage vessel. (This may not always be the case if, for instance, the exact same model of enclosed combustor was reinstalled such that existing piping, foundation, etc. can be used without modifica tion; however, that scenario would be an infrequent exception.) In addition, according to the commenter s , the number of affected storage vessels that get below the 4 tpy threshold in order to remove controls, and then again have a significant increase to r equire controls, will be much fewer than the number of “new” affected storage vessels in any given year; therefore, the same requirements should be sufficient and should apply. Also, the commenter s report that a permitted facility with a storage vessel in this situation must still comply with state air permit limits or permitting thresholds such that the VOC emissions from the affected storage vessel during this uncontrolled period will effectively continue to be limited.

Another commenter ( 4618 ) states th at, should a previously affected facility need to reinstall controls, the ability to find one in less than 30 days could prove extremely difficult. The

commenter recommends that additional time be granted in this instance. T he commenter believes

that 180 d ays would be sufficient time for a site to fi nd a control device. Moreover, the commenter provides that a 180

- day deadline is consistent with the 40 CFR §60.14(g) definition of modification which allows 180 days following the completion of any physical or operational change subject to control measures to comply with all applicable standards.

One commenter (4620) recommends that the reinstallation of controls be required within 90 days of the determining that projected actual or actual emissions are over 6 tpy. The commenter believes that it is more appropriate to require reinstallation at the same 6 tpy threshold applicable to new Group 2 storage vessels or Group 1 vessel with a triggering event rather than the 4 tpy alternative emission limit. The commente r states that these vessels will require the same installation and design requirements as the initial control device installation and

should have the same control threshold.

Response: The EPA maintains that a period of 30 days is appropriate for the inst allation of controls in this circumstance. A period of 30 days is consistent with control requirements that apply to Group 2 storage vessels where an owner or operator has 30 days to install controls once it is determined that a storage vessel is an affect ed facility subject to control requirements.

In response to the comment that suggests the EPA should require owners and operators of storage vessel affected facilities to “minimize emissions to the extent practicable during the 30

- day period using good en gineering practices through the period prior to installation of controls,” we believe that such a requirement could add significant burden and confusion regarding enforcement of undefined requirements.

We are not finalizing the provisions in our proposa l related to tracking emission increase events; therefore any comments related to tracking events are now moot.32



### 2. 2 Stor age Vessel Control Requirements

2.2.1 General Support for Group 1 Storage Vessel Requirements

Comment : One commenter (4623) provides support for the EPA’s proposal to limit the regulatory requirements applicable on October 15, 2013

, for Group 1 storage vessels to notification requirements (and excluding them from control requirements until future facility changes occur).

Similarly, a no ther commenter (4633) provides support for the compliance date of October 15, 2013

, for Group 1 storage vessels.

Response: We acknowledge the commenters support for the initial notification and compliance date for “Group 1 storage vessels” and the EPA’s p roposal to limit the regulatory requirements for Group 1 storage vessels to notification requirements. See section IV. A of the preamble to the final amendments for additional discussion regarding Group 1 storage vessel applicability and compliance dates.

2 .2.2 Control Equipment Design Requirements

Comment: One commenter (4622) who supported the inclusion of design requirements

in the NSPS provides several possible approaches which they believe will assure that equipment is properly designed to meet the sto rage vessel standards:

The EPA could prescribe design criteria for the size of storage tanks; the weight, placement, or material of hatches and covers; the size or rating of control devices; and any other system design elements affecting the pressure in t he tank during loading. The EPA could require the operator to certify both: (1) the maximum emissions expected from the storage vessel, including maximum flash emissions expected during loading or transfer operations, and (2) the capacity of the control sy stem to handle that flowrate. This certification, which resembles the a pproach currently

reflected in s ubpart Kb, could be submitted as part of the existing compliance

- certification process. The EPA could also require an alarm or similar monitoring system for all PRDs, as it proposed in the Uniform Standards, and designate non

- emergency or repeated releases from PRDs as violations of the NSPS. This approach would be consistent with the regulation of bypass lines at clo sed vent systems under current s ubpart OOOO, which requires such bypass lines to be equipped with monitoring systems and regards any release as a deviation. The EPA could also consider requiring equipment that ensures control systems operate under appropriate conditions. For instance, CDPHE has examined “closed

loop” emission capture systems that are specifically designed to recover vapors from

PRDs and thief hatches.

The commenter (4622) also provides that a nother demonstrated technology is the installation of a surge tank between the two or three phase separator and the condensate tank33

battery, which avoids over

- pressurizing the condensate tank. According to the commenter, t his

add

- on equipment is used at existing and low

- flow wells. Alternatively, the commenter suggests

that installing a hig h pressure low

- pressure separator (HLP) essentially causes VOCs from the condensate to flash from the three phase separator r ather than the condensate tank and that s ome operators use HLPs at new and high

- pressure wells.

One commenter (4612) believes tha t prescribing additional design standards would add to the complexity of the rules, thus increasing compliance burdens

.

Two commenter s (4623 , 4628 ) add that operators have sufficient incentive to design and operate their equipment properly to avoid safet y, economic and environmental disruptions

. Moreover, one of the commenter s (4623) argue s that the EPA does not have the authority under NSPS to require a particular technology or design as a performance standard.

Another commenter (4628) reports that OSH A incorporates design standards in their rules in 29 CFR §1910.106. The commenter opines that, if the EPA were to create their own design criteria, it could limit the flexibility operators need to effi ciently operate their facilities. Additionally, accordi ng to the commenter, new design requirements from the EPA may conflict with existing OSHA, industry, or company safety standard s creating an unworkable situation.

Response: As discussed in section V.E of the preamble to the final amendments, we did

not pr opose any specific design requirements and are therefore not finalizing any design requirements for storage vessels and associated closed vent systems and control devices in the

final amendments

.

Comment: One commenter (4611 ) requests that the EPA clarif y that the closed vent

system and cover requirements for storage vessels and centrifugal compressor wet seal degassing systems will prevent emissions during additions of liquid to the storage vessel, especially during high pressure liquid addition. The com menter asserts that this is important to reduce the possibility for an unintended loophole in the rule language which might result in potentially significant emissions.

The commenter (4611) reports that they have observed the highest emission rates

corres ponding to flash VOC emissions while liquids are being added to an existing storage vessel. The commenter states that this is common at well sites, where the natural formation results in high pressure liquids which are then routed through the separator to a storage vessel

that is at or around atmo spheric pressure. The commenter further states that, if a closed cover is not maintained during such liquids addition, a large percentage of the annual emissions could vent out of a pressure relief valve or thief h atch, rather than being routed to a control device and the EPA should not allow exceptions to the closed cover requirements simply for pressure equalization.

Response: As stated in our previous response, we are not finalizing any design requirements at th is time.34

2.2.3 Electronic Ignition Systems

Comment: Several commenter s (4614, 4616, 4619, 4620, 4629 ) request that the EPA

should allow control devices that do not have a continuous pilot light.

According to one commenter (4616) , the proposed rule’s preamble and regulatory text contains an ambiguity which can be interpreted to either permit or disallow the use of electronic ignition, creating confusion in the combustor industry. The commenter states that, in the preamble to the August 2012 final rule , electronic ignition is not mentioned and a reference to continuous flame pilot lights is vague. The commenter states that the last mention of continuous ignition source omits the phrase “over the duration of the flowback.” The commenter believes

the bett er reading is that “duration of flowback” modifies “continuous ignition source” and that it was left off in the last sentence for stylistic reasons. The commenter urges the EPA to clarify this language in the final rule and to indicate that electronic igni tion is permissible. The commenter

suggests clarifying language to proposed provisions § § 60.5415 and 60.5417 to, according to the commenter, unambiguously permit the use of electronic igniters.

One commenter (4633) requests that the EPA consider open

- flam e flare stacks or enclosed vapor combustors equipped with auto

- igniters as acceptable and that this acceptable use specifically be inc orporated into §60.54 1 7(h)

.

One commenter (4616) request s that the EPA consider their enclosed combustor technology, con sisting of an electronic ignition device th at attains a destruction and removal efficiency of 99.99 percent

. This commenter includes their manufacturer’s certification performance test for their enclosed gas vapor combustor

.

According to one commenter (46 16), in response to comments that mentioned that technological innovation made the requirement for a continuous pilot obsolete, the EPA has offered no technical basis for its belief that continuous pilots are more effective than electronic ignition at hand ling “intermittent and inconsistent nature of emissions...combined with highly

variable VOC concentrations.” T he commenter asserts that the EPA implicitly assumes that devices employing a continuous pilot will be effective to control low BTU flowback gas a nd that

in the EPA’s response to commenters request that electronic igniters be permitted in lieu of continuously operating pilot lights, does not provide a quantitative analysis of its assertion that devices employing a continuous pilot will be effective to control low BTU flowback gas.

The commenter (4616) sees no environmental basis to support a conclusion that electronic ignition devices should not be permitted on storage vessel combustors, especially when the igniter is utilized as part of a smart te chnology system with safety features such as pressure monitoring devices, on/off valves that only open when gas is present, and temperature monitoring devices to indicate and record when flame is present and combustion is within the proper operating range. This commenter also states that, in the Natural Gas Star Program, the EPA separately encourages the use of “electronic flare ignition devices” to replace “continuously burning pilot flames.” According to the commenter, absent an analytical comparison of t he relative efficacy of continuous pilots and electronic ignition at combusting VOCs, it appears that one part of the EPA Air Office supports a technology which another part actively disfavors.35

One commenter (4629), regarding a "continuous ignition devic e", requests confirmation that subpart OOOO requires a verifiable continuous standalone dedicated pilot with stable reliable pilot fuel source for an enclosed combustion device operating with vent gas feed to be considered a control device, and that a pilo t should have its own dedicated verification of the presence of its flame. According to the commenter, just as required on a flare, the purpose of a reliable standalone dedicated pilot is to assure there is reliable flame during vent gas feed. Using

a tank 's vent gas itself with its common low pressure and variable component makeup may not be stable in all atmospheric conditions, and thus the device would not meet the intent of the regulation. In addition, the commenter asserts that, unless the pilot is con tinuously burning in anticipation of a release, the time required to ignite and confirm the presence of a flame upon the determination that a release is imminent will very likely lead to a direct vent to the atmosphere either through the control device or via backpressure through the tank pressure relieving device.

Response: The 2012 NSPS requires pilot flames on combustion control devices

. We have not proposed any change to that requirement. As we explained in the Response to Public

Comments document for the August 23, 2011 proposed rule (see p. 307 of the document), w e maintain our position that without a continuous pilot flame, there may be periods of uncontrolled emissions, and continuous ignition sources are designed to combust the flammable portion of the flowback gas, even if the flowback gas has a low BTU content. We also note that in §60.18(b)(2) of the General Provisions for 40 CFR part 60 rules, a continuous pilot flame is required for flares, and we believe the same requirement is applicable to t he combustion control devices typically used for control of emissions from storage vessels in the oil and natural gas industry. As we stated in the response to comments for the proposed 201 1 standards, there is not sufficient data at this time to suggest t hat electronic ignition systems on combustion devices are capable of continuously supplying a constant source of ignition adequate to keep a flame present on a continuous basis. In addition, for flares, test data for which the current standards in §§63.11( b) and 60.18 were written show that operating a flare with a continuously lit pilot adds an additional degree of flame stability to the flare itself.

One of the commenters suggest s clarifying language be made to §§60.5415 and 60.5417

of the final amendmen ts to unambiguously permit the use of electronic igniters. We disagree

. T he final amendments at §60.5412(d)(1)(i) specify the use of a continuous burning pilot flame

. Electronic ignit e rs do not meet this provision. Although an electronic ignition device do es not qualify as a continuous burning pilot flame , it may be used, for example, as a means of re

lighting a pilot flame that has been extinguished by wind or other factor

, as long as a continuous burning pilot flame is maintained when vapors are being rou ted to the combustion device. For the reasons stated above, the final amendments do not include specific regulatory language in §§60.5415 and 60.5417 regarding electronic igniters.

Concerning the comment on whether a continuous ignition device would be r equired on an enclosed combustion device burning vent gas, we confirm that such a device would have to have a continuous ignition device. We disagree with the commenter that such a control device

does not meet the intent of the standards. This is in fact t he emission source and emission control we envision to be subject to the control requirements of §60. 5 395 of the final amendments.36

With regard to commenters’ suggested changes to the compliance requirements in the

2012 NSPS , we continue to evaluate issues concerning the compliance requirements of the 2012 final NSPS. We intend to complete our evaluation of compliance provisions by the end of 2014.

2.2.4 Flares

Comment: Several commenter s ( 4615, 4629, 4630) assert that the EPA should clarify the

control d evice standards as they pertain to flares.

One commenter (4630) reports that the proposed amendments contain provisions that apply to “each control device” and to “each combustion device,” both of which would be applicable to flares. However, the comment er expresses concern that flares are not expressly cited, and there are certain references to “enclosed combustion device(s)” that would seem to be applicable to flares. The commenter suggests edits to §60.5412(d) to clearly identify those provisions which are applicable to flares.

Another commenter (4615) opines that , when §60.5412(a) was modified to apply only to centrifugal compressor affected facilities, and § 60.5412(d) was added for storage vessel affected facilities, it became unclear what needs to be done when using a flare as a control device for a storage vessel affected facility. The commenter proposed that the following change be made to make it clear (bolded language is added):

§60.5412(d)(1) Each flare or enclosed combustion device...

One comm enter (4629) states that § 60.5413 states " A flare that is designed and operated in accordance with §60.18(b) . You must conduct the compliance determination using Method 22 at 40 CFR part 60, Appendix A

- 7, t o determine visible emissions." By the commenters' interpretation, this is defining a typical flare that has been utilized in industry for many years and

as such will achieve a minimum 98 percent VOC destruction efficiency primarily based upon testing sponsored by the EPA and the Chemical Manufacturers As sociation in July 1983. The commenter requests the following changes be made to §60.5413 to reduce confusion: (1) a dd a statement that for normal process VOC reduction use of an open or enclosed flare designed and operated in accordance with §60.18(b) is a cceptable for obtaining VOC destruction efficiency in

excess of 98 percent; (2) a dd a statement that flares used for normal process VOC reduction are required to have a constant burning pilot as defined by API 537 ; (3) c larify what constitutes an

upset con dition which would fall outside of normal process VOC reduction.

Response: The owner or operator of a storage vessel affected facility may use any control technology, so long as compliance with the emission reduction requirement can be

demonstrated. There fore, we do not believe it is necessary to specifically incorporate into the rule that flares, and open

- flame flare stacks or enclosed vapor combustors equipped with auto

igniters (see also the previous comment response) are acceptable for use to meet the required

emission reduction standard. We point out, however, that a flare is not an enclosed c ombustion

device and the definition of flare in the 2012 NSPS specifically points this out. We also believe, considering the variability of flow to the combustion control device from storage vessels, that it is not appropriate to assume that a flare designed and operated in accordance with §60.18(b) is37

achieving the required control efficiency at all times. However, the 2012 NSPS does provide at §60.5413(a)(1) that a flare designed and operated in accordance with §60.18(b) is exempt from performance testing . S uch a flare would still be required to perform Method 22 visual emissions testing.

Additionally, §60.5417(h) specifies continuous control device monitoring re quirements for control devices used to comply with the emission reduction standard of §60.5395(d). The control device requirements of §60.5417(h) would apply to open

- flame flare stacks or enclosed vapor combustors equipped with auto

- igniters (as well as ot her control devices) if used to comply with the emission reduction standard and do not need to be specifically cited as being acceptable.

Although we have not made the commenters’ suggested changes, we continue to evaluate the issues raised by commenters concerning the compliance requirements and flare provisions of the 2012 final NSPS. We intend to complete our evaluation of the compliance requirements and flare provisions by the end of 2014.

2.2.5 Carbon Adsorption

Comment: One commenter (4630) asser ts that the EPA should not require carbon management for carbon absorption systems used with centrifugal compressors. The commenter

requests that the EPA delete § 60.5412(c)(2) in its entirety. The commenter maintains that the pertinent carbon management re quirement for carbon adsorption systems used with centrifugal compressors is specified in §60.5412(c)(1), which is that the carbon must be replaced according to the specified schedule. According to the commenter, the EPA should not be prescribing waste

man agement req uirements within a CAA regulation. The owner/operator has a separate obligation to determine the applicability of regulations under other programs, such as RCRA,

and the commenter opines that it is beyond the purview of an air rule to stipulate the applicability of rules under other programs. The commenter believes it adds unnecessary text to the rule, and

makes it more difficult to discer n what the requirements of the rule are.

Response: The carbon management provisions in the proposed amendmen ts are identical to those in the 2012 NSPS. We included them in the proposed amendments only as part of our effort to separately distinguish the requirements for storage vessels and centrifugal compressors

. Therefore, the carbon management provisions are n ot within the scope of issues addressed by

these final amendments.

2.2.6 Control Device Operating Requirements

Comment: One commenter (4633) asserts that because many states consider vapor recovery devices such as a vapor recovery tower and/or a vapor r ecovery unit as process equipment rather than control devices, it will be confusing for facilities to use vapor recovery devices as "control" under subpart OOOO and as "process" under state permitting requirements. Further, according to the commenter, stor age vessels that include vapor recovery operations (or routing of tank emissions to flow lines for processing) would correctly apply those operations in the calculation to determine whether the storage vessel's VOC emission rate would exceed 6 tpy

or great er for applicability purposes. The commenter states that, for many states, neither the38

vapor recovery device nor the routing of off gas from a tank to a flow line would require permitting. Thus, the commenter believes that the proposed revisions seem to un necessarily require a facility to seek a "legally and practically enforceable limit in an operating permit or by other mechanism" (§60.5395(e)). The commenter is concerned that this approach could lead to process piping within a facility being considered " control."

Response: First, we believe the commenter may have confused the usage of similar terms that are used in the NSPS. Vapor recovery devices are control devices such as a carbon adsorber or a condenser. A vapor recovery unit is a piece of equipment

, usually a compressor, that collects a gas stream and returns it to the process for a useful purpose, such as recovery, recycling or

reuse. The 2012 NSPS final rule includes a definition of “routed to a process or route to a process” as including emissions that “are conveyed via a closed vent system to any enclosed portion of a process unit where the emissions are predominantly recycled and/or consumed in the same manner as a material that fulfills the same function in the process and/or transformed by

chem ical reaction into materials that are not regulated materials and/or incorporated into a product; and/or recovered.” Vapor recovery units and flow lines that would meet this definition would be considered part of the process and would not be considered con trol devices that are subject to the control requirements under the final amendments . We believe that the commenter has misinterpreted the vapor recovery device requirements considered to be control devices

under the NSPS with vapor recovery units. However , we point out that the final amendments include provisions for consideration of emissions routed through vapor recovery units in determining storage vessel’s potential to emit for purposes of affected facility determination. See

section IV.C of the preamb le to the final amendments for a discussion of this issue.

Comment: Two commenters ( 4615, 4630) request that the EPA clarify that control devices need only be operating when vapors are being routed to the control device.

One commenter (4615) states that a VRU is usually set to operate only when needed and that the EPA should clarify that the control device must be operating when vapors are actually being pushed through the control device

. The commenter suggests the following wording changes to §60.5415(e )(3)(ii)(C) to ensure the correct interpretati on of the word, “operational” :

§60.5415(e)(3)(ii)(C) ( commenter added bold language and deleted word "operational" ) : Each closed vent system that routes emissions to a flow line, as defined in §60.5430,

must b e capable of being operated when the storage vessel affected facility is in

service 95 percent of the year or greater.

This co mmenter (4615) also states that a flare or enclosed combustion device should only be required to be in operation when there is fl ow into the storage vessel affected facility and provided the following suggested language changes to §60.5412(d)(3) to address their comment:

§60.5412(d)(3) (bold language added and "are" removed): You must operate each control device used to comply wit h this subpart at all times when there is flow into the storage vessel causing gases, vapors, and fumes to be vented from the storage vessel affected facility through the closed vent system to the control device. You may vent more than

one affected facilit y to a control device used to comply with this subpart.39

Response: We considered the commenters’ suggested edits. We did not make the suggested edits to §60.5415(e)(3) because we do not believe they would add clarity to the rule

and the determination of wh en a closed vent system is “capable” of being operated presents significant enforcement challenges. We did not make the suggested edits to §60.5412(d)(3) because, even when there is no flow into the storage vessel affected facility, there are still

emissio ns from breathing losses that occur when there is no liquid flow being introduced to the storage vessel.

2.2.7 Storage Vessel Alternative Control Requirement

Comment: Several commenters (4611, 4615, 4630) request that the definition of flow

line be amen ded so that it applies to production field facilities and natural gas processing plants.

One c ommenter ( 4630 ) recommends amending the definition of flow line to read as

follows:

Flow line means a pipeline used to transport oil and/or ga s from the well or process to processing facility, a mainline pipeline, re

- injection, or other useful purpose. The flow line includes any process equipment, such as a compressor, used to introduce a vapor stream into a pipeline or into other useful processes.

Another co mmenter (4615) requests that the storage vessel alternative control requirement allow for the use of vapor recovery to a flow line be modified to be applicable to

m idstream storage vessels. The c ommenter suggests 2 options t o address their concerns:

Opti on 1 : Modify the definition of "flow line" to read as follows:

Flow line means a pipeline used to transport oil and/or gas from a well or process to a processing facility, a mainline pipeline, re

- injection, or other useful purpose. The flow

line includes any process equipment, such as a compressor, used to introduce a vapor stream into a pipeline, process line, fuel system or into other useful processes.

Option 2 : Modify the rule language (e.g., §60.5395(e)(1)) wherever the alternative compliance option i s addressed to read as follows:

As an alternative to routing the closed vent system to a control device, you may route the closed vent system to a flow line, as defined in §60.5430, or to a process natural gas line. If you route vapors to a flow line, or to a process natural gas line, you must equip the storage vessel with a cover that meets the requirements of §60.5411(b) and is connected through a closed vent system that meets the requirements of §60.5411(c).

Response: We considered and agree with the commenters’ request that the definition of

“flow line” be amended so that it does not appear to be restricted to flow that originates at a well. In order to address commenters’ concerns, we made the following changes to the definition of

“flow line” in the final amendments :40

Flow line means a pipeline used to transport oil and/or gas from the well to a processing facility, a mainline pipeline, re

- injection, or routed to a process or other useful purpose.

It is important to note that the 2012 NSPS includes a definition of “routed to a process or route to a process” as including emissions that “are conveyed via a closed vent system to any enclosed portion of a process unit where the emissions are predominantly recycled and/or

consumed in the same manner as a material that fulfills the same function in the process and/or transformed by chemical reaction into materials that are not regulated materials and/or incorporated into a product; and/or recovered.” Flow lines that would meet this definition would

be consi dered part of the process and would not be considered control devices. We believe that, using this defined phrase within the definition of “flow line” addresses the commenters’

concerns.



### 2. 3 Storage Vessel Recordkeeping Requireme nts

Comment: Several comm enters (4615, 4620, 4626, 4630) requ est that the EPA allow owners and operators to maintain records off

- site and/or maintain records in electronic format rather than paper format.

One commenter (4633) states that §60.5412(d) proposes that "all inspection, repair, and maintenance activities ... be recorded in a log ... available on

- site for in spection." Instead of requiring that these logs be maintained on

- site, the commenter proposes that such logs be "kept in a readily accessible location" as is required in other NSPS regulations. The commenter reports that they, like many operators, maintain required records in an electronic format, which allows both field and corporate personnel to readily access data and records without time

- consuming trips to remote lo cations to confirm record availability.

One commenter (4630) asserts that there is no need to maintain records onsite if they can be retrieved within a reasonable peri od of time. The commenter states that this is particularly true for unmanned sites, wh ere there are no personnel available to maintain records. Further, the

commenter asserts that production facilities often lack adequate building space to store records.

Two commenter s (4620 , 4626) recommend that any records required by the rule, such as proof of inspection and monitoring such as those in §60.5412(d)(1)(iii) not be required to be kept onsite, but be allowed to be maintained electronically or at the nearest field office.

Another commenter (4626) asserts that m any affected v essels are loca ted in r emote areas and protecting records from exposure to the environment is diffi cult. Additionally, the commenter reports that some operators conduct inspections and monitor certain equipment electronically, and therefore do not always generate “paper copies” on location. The commenter opines that d ictating that hard copies be maintained onsite is not necessary and may not be the best or most feasible way to retain the important information. The commenter asserts that,

p roviding the operators the reques ted flexibility would benefit industry without h arming the environment or reducing the EPA’s ability to monitor compliance effectively.41

One c ommenter (4615) requests that the EPA remove the word “onsite” from
§ § 60.5413(e )(4) and 60.5417(h)(3), and remove of the sentence “Manufacturer’s records must be maintained onsite” from §60.5420(c)(14).

Response: We agree with the commenters that it is not necessary for facilities to retain

records onsite because there are typically no structures (such as offices) at well sites where documentation may be stored protected from the environment. We also clarify that there are no requirements in the 2012 NSPS that specify records must be maintained only on paper. Therefore, we have revised the final rule (§§60.5412(d)(1)( iii), 60.5413(e)(4), 60.5415(b)(2)(vii)(C), 60.5417(h)(3), 60.5420(c)(13)) to reflect that records do not need to be

maintained onsite. Further, we have amended §60.5420(c) to state that all records required by this NSPS may be kept onsite or at the neares t field office. The 2012 NSPS does, however, specify that records must be made available for inspection. If the owner or operator chooses to maintain records offsite, then they are still responsible to provide those records during inspections.

Comment: O ne commenter (4630) requests that §60.5420(c)(5)(iv) be edited to specify that the record of the length of time a storage vessel has been located at a site should be required to be maintained only while the storage vessel is actually onsite. Also, the comm enter maintains that the drop

- off and pick

- up receipts should suffice as records of the duration of time that the

vessel was onsite.

Response: T he carbon management provisions of §60.5420 (c)(5)(iv) are not within the scope of issues addressed by these fin al amendments.



### 2.4 Storage Vessel Notification and Reporting Requirements

2.4.1 Initial Notification Exemption for Compressors

Comment: Two commenters (4612, 4620) support the proposed revisions that add centrifugal and reciprocating compressors to the list of facilities that are not required to submit the notifications required by 40 CFR 60.7(a)(1), (3), and (4). According to one commenter ( 4612 ) , it is appropriate that this exemption be extended to centrifugal and reciprocating compressors for the same reasons that well completions, pneumatic controllers and storage vessels are exempt from the notifications required by 40 CFR 60.7(a)(1), (3) and (4) in the final

2012 rule.

Response: We acknowledge the commenters’ support and have finalized the revision s to add centrifugal and reciprocating compressors to the list of facilities that are not required to submit the notifications required by 40 CFR 60.7(a)(1), (3), and (4).

2.4.2 Initial Notification for Group 1 Storage Vessels

Comment: Two commenters (46 15, 4630) request that the EPA allow initial notifications for Group 1 storage vessels to be submitted with the initial annual report. T he commenters state
that the proposed standard for Group 1 storage vessel affected facilities is to submit a notificatio n42

with storage ves sel identification and location, which is t he same information required in the initial annual report which is due just 90 days later. The commenters state that, in order to avoid unnecessary duplication of reporting, the notifications for Group 1 storage vessel affected facilities should be specified as being due with the initial annual report, due 90 days after October 15, 2013. One c ommenter ( 4615 ) also states that requiring the submittal of these

notifications 9 weeks after the final am endments are signed by the Administrator leaves little time to collect and compile the data required for submittal.

One commenter (4633) states that 40 CFR §60.5420(a)(3) and (b)(6)(i) requires the October 15, 2013

, notice of Group 1 storage vessel affec ted facilitie s to be accurate to five decimal degrees latitude and longitude in N orth A merican D atum (NAD) 19 83 format. The

commenter requests additional time to gather latitude and longitude information for Group 1 storage vessel affected facilities

.

Ano ther commenter (4623) requests that the EPA clarify that notifications are only required for tanks that exceed the 6 tpy threshold on October 15, 2013.

Response : We considered and agree with the commenters’ request to allow initial

notifications for Grou p 1 storage vessels to be submitted with the initial annual report to reduce the burden of having to submit duplicate information only a few months apart. Therefore, the final amendments (§60.5420(b)(6)(iv)) allow submittal of the Group 1 storage vessel af fected facility notification with your initial annual report. By allowing the initial notification for Group 1 storage vessels to be submitted with your annual report additional time to gather latitude and longitude information will be provided. We also cl arify that only Group 1 storage vessel affected facilities (Group 1 storage vessels with the potential to emit VOC of 6 tpy or more ) , not all Group 1 storage vessels, are subject to the notification requirements.

Comment: One commenter ( 4630) recommends t hat the EPA clarify the latitude/longitude coordinates and datum requirements (required in the initial notification and initial annual report) . The commenter assert s that GPS devices and other systems tend to display latitude and longitude coordinates t o 5 decimal places, but that does n o t mean they are absolutely

accurate to 5 deci mal places. The commenter reque s ts that §60.5420(a)(3) be modified to specify that the system is “represented by the vendor” to an accuracy of “five (5) decimals of a degree plus or minus 30 feet.” Furthermore, the commenter asserts that GPS devices and other systems for determining latitude and longitude do not a ll use the NAD 1983 format , and there is no reasonable rationale for requiring this reference.

Response: The proposed amendments did not include revisions to the sections of the NSPS addressed by this commenter and are, therefore, not within the scope of issues addressed by these final amendments.

2.4.3 Responsible Official

Comment: Several commenters (4613, 4615, 4623, 4628, 4630) request that the EPA remove the requirement for annual reports to be certified by a responsible official

.43

One of the commenters (4623) asserts that the requirement for minor sources regulated under the rule to submit annual complian ce certifi cations signed by a “responsible official” was reserved for major sources (and not minor sources) by Congress under the CAA

.

Similarly, another commenter ( 4615 ) opines that the requirement for certification by a responsible official is overreaching for an NSPS regulation addressing minor emissions sources.

The commenter asserts that c ertification by a r esponsible o fficial should not be required for what are usually very small sources. According to the commenter, i f required, delegation to local field

super vision should be provided. Furthermore, the commenter asserts that o btaining the necessary information and preparing these reports and obtaining a r esponsible o fficial signature will be very difficult to complete within 30 days, especially since these repo rts will be due at many different times throughout the year. The commenter suggests that, i f the EPA insists on a responsible o fficial signature, then moving the time from 30 days to 90 days will at least help give operators sufficient time to obtain, prep are, and certify the information necessary for the annual reports.

Two commenter s ( 4628, 4630) argue that the requirement for a r esp onsible o fficial as

defined in t itle V to certify annual compliance reports for a rea sources is inappropriate a nd overly bu rdensome. The commenter s suggest that the EPA develop a certifi cation requirement specific to s ubpart OOOO that uniquely defines a responsible official as someone much lower in the management hierarchy. According to the commenter s , this would result in a p erson with more direct knowledge of the operations being requested to certify the report, with no lo ss of accuracy or truthfulness. The commenter s state that

, unlike a t itle V site which has a defined boundary and a relatively fixed number of emission sour ces for which compliance must be certified, many oil and gas operators will have sources regulat ed under s ubpart OOOO that will be dispersed among hundreds or thousands of small sites across wide geographic areas. The

commenter s are concerned that the numb er of sources requiring annual certified compliance reports will continue to grow as more and more regulated sources are constructed. As a result,

the commenter s state that the reporting burden will compound each year. According to the

commenter s
, requirin g a t itle V equivalent responsible o fficial to absorb this ever increasing burden will detract from that person’s normal management responsibilities, and make it increasingly difficult to conduct the necessary “reasonable inquiry” necessary for certificati on as high level managers, particularly for larger companies, do not have direct oversight of the operations requiring compliance certif ication. The commenter s assert that it is much more appropriate to push the certification requirement down to the manage ment level that has direct oversight of the oper ations. The commenter s maintai n that this would more effectively spread the load of certification among more supervisors and reduce the burden as it continues to grow over time. The commenter s further state t hat with direct oversight of operations, local or regional management is in a much better position to conduct “reasonable inquiry” to certify the truth and accuracy of the report. According to the commenter s , if responsible o fficial is defined under

s ubpar t OOOO as a first line operations or regulatory supervisor with direct oversight of operations or any higher level of manage ment, operators will have the flexibility of determining who is the most appropriate person to certify reports based on their organi zational structure and hierarchy and will accommodate both large and small operators.44

Another commenter ( 4623 ) states that the requirement for an annual compliance certification by a responsible o fficial is burdensome and inappropriate for this source cat egory. The commenter asserts that, w hile it may work for large t itle V facilities, it is not true for the oil and gas sector. The commenter reports that, a t a typical t itle V facility, the responsible o fficial is the plant manager who is typically located at the facility, has responsibility for overall plant operations, and is in daily contact with operations and compliance personnel. According to the commenter, i n the oil and gas sector, the affected sources are spread out over large areas and are only inf requently visited by personnel. Additionally, the commenter repor ts that the requirement

that a r esponsi ble o fficial have overall responsibility over one or more facilities that employ more than 250 persons or have sales exceeding $25 million (1980 dollars ) does not work well for oil and gas facilities that are generally very small with no full time employees and low revenue. The commenter asserts that, t o meet these requirements it will likely require a high

- level official within the company who will not h ave working knowledge of the day

- to

- day operations of the oil and gas wells. The commenter encourages the EPA to seek to have personnel in supervisorial roles closest to the operation submitting the reports to the Agency. The commenter asserts that

the se p ersonnel will still have a significant level of responsibility and also be far more knowledgeable of the day

- to

- day operations of the affected sources than would a responsible

o fficial as the EPA defines it. The commenter asserts that the EPA would still a chieve its goal of assuring the public that the information submitted is accurate while reducing the burden on the regulated companies.

One commenter (4613) states that the r esponsible o fficial would be required to sign annual reports certifying the truth , accuracy and completeness of the information contained therein for a substantial number of small affected facilities spread over a large area. According to the commenter, w ith re gards to their company , there are only a few vice

- presidents or o fficers

tha t would qualify as a r esponsible o fficial

. The commenter recommends that the EPA develop

alternative r esp onsible o fficial criteria for this NSPS so that field management personnel, who are closer to the day

- to

- day affected facilities and likely more knowle dgeable to make a reasonable inquiry to certify "truth, accuracy and completeness" of information in the report, qualify. The commenter requests that alternative criteria language in the rule would allow additional company personnel to sign annual reports for this NSPS and would streamline the reporting process, facilitate verification of report content and ease compliance.

Response: The requirement for the annual report to be signed by a responsible official is not within the scope of issues addressed by these final amendments. However, we have finalized the proposed amendment that submittal of the annual report and compliance certification be extended from 30 days to 90 days after the compliance period. We believe this will give operators and the designat ed responsible official sufficient time to obtain, prepare, and certify the information necessary.

2.4.4 Reporting Deadline

Comment: Severa l commenters (4612, 4613, 4617, 4620, 4624 , 4633 ) provide support for extending the annual report and compliance ce rtification reporting deadline to 90 days past the end of the compliance period.45

Specifically, three commenters (4612, 4613, 4624) support the EPA ’s proposal to amend
§60.5420 to allow 90 days from the end of a compliance period for facilities to submit their annual report and compliance certifications. Two of the commenters (4612, 4624) assert that t he proposed change to §60.5420(b) would make the reportin g requirements consistent with t itle V requirements and certification requirements

.

Two commenter s (4612 , 4613 ) assert that a large number of facilities/companies would have many sources covered by these rules necessitating the additional time to submit their annual

report. One c ommenter ( 4613 ) asserts that , for their company, a large number of affecte d facilities would need to be rolled up into one report that would be signed by one Vice

- President and that this requires addit ional time in order that the r esponsible o fficial (in this case the Vice

President of their company) can perform a reasonable inq uiry that would be necessary to achieve compliance. Similarly, commenter 4612 asserts that affected facilities need the additional time to compile, verify, and report the required information.

Two c ommenter s (4617 , 4620) state that production, monitoring , and other operational data are typically not available for at least 60 days after the close of the month, so 90 days are necessary in order to compile and verify the report.

Response: We acknowledge the commenters support and have finalized the proposed amendments to allow 90 days after the end of the compliance period for submittal of the annual report and compliance certification.



### 2.5 Compliance Demonstration and Monitoring Provisions

2.5.1 Vapor Recovery Units

Comment : One commenter (4613) requests that the EPA explicitly confirm that vapor recovery units (VRUs) are considered process devices , not control devices, in the rule

.

Response: The EPA clarifies that VRUs that route emissions to a process are considered part of that process and are not co nsidered control devices.

2.5.2 L eaking C losed V ent S ystems and C overs

Comment: One commenter (4622) asserts that the EPA should not extend the repair periods for permanent repair of storage vessel leaks to 30 calendar days. According to the

commenter, t he EPA did not provide any explanation of or support for, and did not mention in the preamble, the proposed extension of time allowed for permanent repair of storage vessel

leaks to 30 calend ar days. The commenters report that s ubpart OOOO currently requir es permanent repairs of observed leaks within 15 days. The commenter referred to a court case where an agency changing its course must supply a reasoned analysis [ Cf. Motor Vehicle Mfrs.

Ass'n v. State Farm Mut. Auto. Ins ., 463 U.S. 29, 57 (1983)]. The com menter states that the 30

- day repair deadline is significantly less stringent than some of the state and local requirements currently in effect. The commenter reports that some states require repairs to be completed

within 72 hours of detection.46

One comme nter (4611) requests that the EPA clarify when sources would be required to complete repair of a closed vent system or cover for which a leak has been discovered if repair is delayed.

Response: In the preamble to the proposed amendments (see 78 FR 22134), we discussed issues raised by petitioners related to the compliance monitoring requirements and the burden these requirements placed on affected facilities in light of our revised estimate of the number of storage vessel affected facilities. In response t o these concerns, the EPA proposed certain streamlined monitoring and compliance demonstration requirements and we are finalizing the streamlined requirements in the final amendments. One aspect of the streamlined requirements is

the increase in the time t o complete permanent repairs from 15 days to 30 days. We continue to

believe that

, because of the large number of storage vessel affected facilities along with the remoteness of their location, a longer period of time to complete permanent repairs is warra nted.

We note that we continue to evaluate the issue raised by commenter s concerning the more stringent compliance provisions of the 2012 final NSPS. We intend to complete our evaluation of monitoring provisions by the end of 2014.

Concerning the comment on when repairs must be completed if the repair is delayed, §60.5416(c)(5) of the final amendments specifies that such repairs must be completed at the next

shutdown.

2.5.3 Performance Testing

2.5.3.1 Manufacturer’s P erformance Testing Requirements

Comme nt: One commenter (4633) supports the use of manufacturer information to demonstrate compliance with control efficiency requirements. The commenter also supports the use of visual, olfactory, and auditory inspections of the facility

.

Several commenters ( 4 612, 4614, 4618, 4620) support manufacturing testing provisions that allow for the certification of specific device makes and models.

One commenter (4614) states that, by allowing the control device manufacturers to perform compliance testing on the spec ific model of control device over a range of operating conditions, the EPA can ensure that these devices will meet the percent reduction requirements of the rule, while still requiring owners and operators to monitor site specific operating

conditions to d emonstrate that actual operations are within the design parameters of the control

device.

Another commenter (4618) generally supports the concept of certifying a unique control device model based on a single set of tests as stipulated in proposed §60.5413 (d). The

commenter states that the model of control device that will receive a certification based on testing of the same model should have the same physical and operational characteristics such that the same (successful) compliance test would have resulte d if the manufacturer had actually run

the same tests on each certified device.47

One commenter (4620) support s the manufacturer testing provisions that allow for the certification of specific device makes and models and aligns testing requirements between
NESHAP s ubpart HH and NSPS s ubpart OOOO.

Other commenters (4629, 4630) express concern over the use of manufacturers performance testing being allowed to demonstrate compliance with control efficiency requirements.

One commenter (4629) states that they d o not believe that manufacturers performance testing will be representative of actual field performance of the control device environment when the equipment is operated in the field. According to the commenter, temperature control would require capability to control both air feed and fuel feed and be a more expensive system to provide and that adherence to the requirement that the system is designed and operated in accordance with §60.18(b) should be a sufficient requirement to avoid costly temperature cont rol require ments for these control devices

.

Another commenter (4630) states that they support innovative approaches that would truly reduce the burden on EPA, the states, and the regulated community. However, the commenter opines that if the Agency intend s to expand their reach into identifying specific pollution control manufacturers and models that are “compliance ready,” there are likely many years of work that will need to be done in advance of finalizing any rule to avoid compliance complications for the regulated community. The commenter questions whether or not this will truly result in a burden reduction or only complicate compliance and the rulemaking process. Finally, according to the commenter, the introduction of new or innovative approaches to CAA compliance should not take place within proposed amendments for a single source category. The commenter encourages the EPA to seek ways to streamline compliance and reduce the burden on all affected parties. However, they believe that the EPA should pr opose these new approaches in

a separate Federal Register notice as an Advanced Notice of Proposed Regulation and take comment from all source categories that are subject to NSPS. In any event, the commenter opines that the Agency should not finalize this approach in this rulemaking until it has worked

with all stakeholders.

Response: The EPA thanks the commenters for their support concerning amendments to the combustor control device manufacturer test protocol and associated reporting requirement to align them with similar provisions in the Oil and Natural Gas NESHAP (40 CFR 63, subpart HH) , and clarify that manufacturer testing is not mandatory

. 71 FR at 22135. Regarding the

broader comment questioning the use of manufacturer performance testing, its use was finalized in the 2012 NSPS. The matter was not reopened for notice and comment and, therefore, is not within the scope of this rulemaking

.

Regarding one commenter’s recommendation that adherence to the requirement that the system is designed and ope rated in accordance with §60.18(b) should be a sufficient requirement to avoid temperature control requirements for these control devices, the EPA notes that §60.18(b) applies specifically to flares and is not applicable here to enclosed combustors. Regard ing one commenter’s recommendation that the EPA propose new approaches and take comment for all source categories subject to NSPS, we note that this is beyond the scope of this

action.48

Regarding the comments related to innovative approaches, we do not con sider manufacturer testing to be a new concept introduced in this rule. The Agency has used this approach in other rules in the past and has not experienced any of the unforeseen complications

o r years of delay envisioned by the commenter.

Comment: One co mmenter (4624) requests that the EPA ensure that certification of

combustors as “ compliance ready ” take into account proper design, installation and operation requirements. The commenter is concerned that the EPA's certification of combustors as "complianc e ready" based on manufacturers' performance testing would not take into account proper site

- specific design requirements, installation, o r operation of the combustors.

Response: The NSPS , including today’s amendments, does not include a certification

p rocess ; rather

, it includes a control device manufacturer testing protocol, which requires three

one

- hour test runs for each of four rate settings to verify that the control device can meet the control requirements of the 2012 NSPS under a variety of condi tions . To the extent the commenter is asking whether the manufacturer testing protocol account s for site

- specific design, installation or operation , they are not covered in the protocol because the EPA believes that it is the responsibility of the owner or operator to properly select and install a combustor based on

site

- specific needs. However, we note that the final amendments include initial and continuous compliance requirements to help assure proper operation of the control device.

Comment: One commen ter (4629) requests that the EPA clarify whether they are providing design certification requirements for enclosed combustors. According to the commenter, if the EPA provides design certification requirements for enclosed combustors, they

assume this certi fication will be public and complete in providing what operation range it has been tested and certified. The commenter further states that they assume that the EPA will defend an EPA certified design at EPA expense as needed in questioned performance litig ation.

Response: EPA clarifies that n either the 2012 NSPS nor the final amendments include desig n certification requirements for enclosed combustors. Rather, the NSPS allows manufacturer testing in lieu of field testing and includes a manufacturer testing protocol which requires three one

- hour test runs for each of four rate settings to verify that the control device can meet the control requirements of the 2012 NSPS under a variety of conditions

. We believe that operators have an incentive to use manufact urer

- tested combustors because those combustors have reduced frequency of visible emissions testing

. The NSPS prescribes a specific test protocol

that must be followed and certain criteria that must be met for manufacturer

- tested combustors, including no v isible emissions , emission limits for THC and CO and a percent excess air requirement . Once a model has been tested and a complete test report is sent to the EPA, we will review the test report to ensure that the model tested meets the required criteria. T he EPA will post the models meeting the combustor test protocol on our website (listed in the final

amendments ).

Comment: One commenter (4614) requests clarification on whether a test protocol is required to be submitted to the EPA for approval prior to conducting the performance test if the procedure s in §60.5413(d) are followed. The commenter requests that, if pre

- test protocol49

submittal and approval is not required, that the option to submit a protocol for EPA approval for deviations from the test prot ocol be outlined in the rule.

Response: We do not require that a performance test protocol be submitted to the EPA prior to conducting the manufacturer performance test . We also decline to include the option to submit for EPA approval a request for deviat ion from a test protocol. The performance test procedures in the final rule must be followed and a complete test report must be submitted to the

EPA before a model that meets the required criteria will be listed on the EPA’s website.

Comment: One commen ter (4618 ) states that the EPA solicited comment on a potential compliance approach based on the use of these manufacturer

- tested combustor models. The commenter suggests that EPA Method 19 should be considered as an alternative flow

measurement method. Th e commenter reports that t his method uses either the O 2 or CO 2
concentr ation, the fuel "F" factor, and fuel flow rate to calculate the emission flow rate using

stoichiometric calculations.

Response: The EPA declines to include Method 19 as an alternative measurement
method

. Method 19 does not explicitly provide details for the calculation of flow rate. Given that the manufacturers’ performance tests will be used by a variety of manufacturers, the EPA believes that each test should be conducted consistently . Thus, the EPA will not allow Method

19 as an alternative flow rate measurement.

Comment: One commenter (4614) states that they do not believe that a requirement for manufacturers to report the names of entities that had purchased certified control devi ces will provide any additional compliance certification for the EPA. According to the commenter, once the unit is purchased, the manufacturer loses control over where the unit may be installed, whether the unit is resold, if the unit is moved or otherwise maintained and operated in a manner consistent with manufacturer recommendations, etc. Therefore, the commenter believes that such a report will be quickly outdated and lose its effectiveness as a compliance evaluation tool.

Response: We do not require t hat a manufacturer report the names of entities who purchase their control devices.

2.5.3.2 Coll ecting the Gas Sample in a B ag

Comment: One commenter (4618) states that §60.5413(d)(7)(i) specifies collecting the gas sample in a bag for analysis using a ga s chromatograph

- thermal conductivity detector. According to the commenter, collecting samples in a bag can create a number of problems. The commenter suggests that the EPA include the option of pulling the sample directly from the

source into the instrumen t via a heat

- traced sample line in the rule.

Response: Although the commenter may have concerns about collecting the gas sample in a bag, the commenter did not sufficiently explain the potential problems with bag sampling,

and t he EPA is making no change in the final amendments with regard to gas sample collection procedures

. V ariations to established test methods must be evaluated on a case

- by

- case basis to avoid unintended consequences that may result at other facilities having different operating

condit ions or situations than those presented by the commenter. However, we note that a source50

may make a request to the EPA under the provisions of § 60.8(b) for an alternative test method, including direct sampling as an alternative to bag sampling.

2.5.3.3 U se of Alternative Gases as the Testing Fuel

Comment: Two commenters (4629, 4630) request that the EPA allow the use of alternative gases as the testing fuel when conducting manufacturer’s performance tests.

One commenter ( 4630) recommends that the EPA a llow the use of propane, rather than

pr opene, as the testing fuel for the manufacturers' performance test. The commenter opines that the preferred gas for the testing fuel should be propane, rather than propene. According to the commenter, use of the turn

- up and turn

- down of fuel to set an operating envelope, as required by this rule, would result in a more representative performance curve if the testing fuel were propane, in that propane is more representative of field conditions and thus is a better indic ator of representative performance than is propene. Furthermore, the commenter asserts that propene is less readily available, more costly, and is a more highly reactive VOC than propane.

The other commenter (4629) requests that the test gas for manufactu rers performance testing be cha nged to methane or ethane to be, in their opinion, more reflective of the intent of the regulation. The commenter provides that their understan ding is that the intent of the s ubpart OOOO regulation is to reduce methane and et hane emissions to the atmosphere and methane and ethane make up a majority of the gas constituents in the applications that will be most affected by the regulation. T he commenter states that, if reduction in methane and ethane is the intent, propene does n ot have relevancy in this testing. According to the commenter, all testing for the manufacturer's performance test requires propene as the test gas to determine VOC destruction efficiency. The commenter states that, not only is propene an easier hydrocarbo n to destroy than methane or ethane but it is also a less available and more expensive gas to test with than methane

or ethane.

Response: The EPA notes that propylene gas has long been the standard fuel for flare testing, and is a more rigorous fuel with which to display performance than propane, methane or ethane. In addition, it is not feasible to require field gas as the test fuel as field gas varies greatly by region and basin and transport to the manufacturer would be difficult. Propylene was chosen

as the manufacturer test fuel to ensure that a tested model would sufficiently destruct VOC in the field and was also used as a test fuel by another combustor manufacturer when performing controlled testing of combustors in recent years.

2.5.3.4 Alternati ve to Method 4

Comment: One commenter (4618 ) reports that §60.5413 specifies Method 4 for determining moisture and requests that the EPA consider FTIR instrumentation using EPA

Method 320 or ASTM D6348

- 12 as an alternative test method to Method 4 where it is applicable. The commenter states that Method 4 requires pulling stack gas through chilled impingers containing water and silica gel and measuring the sample volume with a calibrated dry gas meter. According to the commenter, the percent moisture is calc ulated using the volume/weight gain in the impinger train. The commenter states there currently are several51

instrumental methods available that can monitor stack moisture. The commenter reports that 40 CFR 75, §75.11(b)(2) describes several options that ar e currently in use and that advances in instrument technology, such as Fourier Transform Infrared (FTIR) Spectroscopy, can monitor multiple analytes, including moisture.

Response: T he EPA is making no change in the final amendments with regard to

alternat ives to Method 4 in response to this comment

. The EPA evaluated this comment and determined that the commenter did not provide sufficient quality assurance/quality control (QA/QC) procedures, such as spiking procedures, to include Method 320 or ASTM D6348

- 12 as

alternatives to Method 4. We also note that v ariations to established test methods must be

evaluated on a case

- by

- case basis to avoid unintended consequences that may result at other facilities having different operating conditions or situations than those presented by the

commenter. However, we note that a source may make a request to the EPA under the provisions

of § 60.8(b) for an alternative test method

.

2.5.3.5 Integrated b urner system

Comment: One commenter (4614 ) seeks clarification on whether a n integrated burner system to manage emissions from storage vessel s (or any similar system) would be subject to two sets of testing requirements: (1) when firing the vented emissions in the burner, the unit meets the intent of the process heater/boiler con trol option exempt from performance testing in §60.5413(a)(3); and (2) when use of the supplemental afterburner would be classified as a control device that requires either the manufacturer testing or site

- specific testing in §60.5413.

Response: We have reviewed the information submitted by the commenter, and believe that an integrated burner system, as described by the commenter, would be a combustion control device and not a heater or boiler. Therefore, the integrated burner system described would be

su bject to the applicable requirements for combustion control devices.

2.5.3.6 Visible Emissions and Method 22 Requirements

Comment: One commenter (4611) requests that the EPA clarify what period of time

would constitute a visible emissions violation. The co mmenter reports that the preamble and rule

are inconsistent.

Response: The EPA clarifies that for manufacturer

- tested enclosed combustors the required frequency of the Method 22 test is quarterly and devices must be operated with no visible emissions, ex cept for periods not to exceed a total of 2 minutes during any hour. For all other combustion controls, the required frequency of the Method 22 test is monthly and devices must be operated with no visible emissions, except for periods not to exceed a total of one minute during any 15 minute period.

Comment: O ne commenter (4630) recommends that the EPA change the Method 22 observation period for the manufacturer

- tested devices to match the requirements for devices not tested by the manufacturer. Specificall y, the commenter requests that the observation period for

manufacturer

- tested devices be 15 minutes rather than 1 hour. The commenter asserts that using a 1 hour observation period and the Method 22 test method would require the operator to dedicate

an hour and 15 minutes to complete the visible emissions observation. At a minimum, the52

commenter states that this would result in an additional 1 hour of time on

- site for a lease operator and subsequently fewer facility visits per day/week/month, etc. The commen ter opines that all that should vary between manufacturer

- tested devices and those not tested by the manufacturer is the minimum frequency of site inspections (i.e., quarterly rather than monthly).

Response: T he EPA is finalizing the streamlined complian ce monitoring requirements, as proposed, with minor clarifying changes. As we stated in the preamble to the proposed amendments (78 FR 22134), we will continue to fully evaluate the compliance demonstration and monitoring issues. We intend to complete our reconsideration of these requirements, along with other issues for which we intend to grant reconsideration, by the end of 2014. We note, however, that the Method 22 test frequency for manufacturer tested units is quarterly, so that

even with an observatio n period of 1 hour we do not believe a quarterly test would result in a significant burden as the commenter suggests.

Comment: Three commenters (4619, 4623, 4630) request that the EPA clarify the EPA Method 22 requirements. The commenter s ( 4623, 4630) op ine that the EPA should only require Method 22 inspections when smoke or visible emissions are observed, rather than monthly

, whereas the other commenter (4619) suggests that the EPA substitute the current Method 22 test requirements for a “smoke/no smoke” test.

Response: Method 22 is a test for the determination of th e frequency of smoke

emissions. It is a F ederal reference method which was proposed and promulgated and is used in many EPA rulemakings. It is a simple test method which can be used to inform operators of potential combustion con trol device issues/malfunctions

. The EPA believes that performing a Method 22 test only if smoke is seen will not assure the same level of compliance as a periodic

Method 22 test.

Comment: One commenter (4630) argue s that the EPA should change the references to the Method 22 test procedure to specifically reference section 11.4.1. The commenter states that the Method 22 procedure should be more specifically referenced to identify the intended requirements of section 11.4.1, so as to avoid the unintended prescription of the form and sketch specified in sections 11.2 and 11.5. Also, according to the commenter, given that the specified

15

- minute observation period does not have any breaks, the commenter maintained that

m easurement of the duration of that period does not require a stopwatch. According to the commenter, any type of chronometer, such as a clock, ordinary wristwatch, cell phone or computer would be suitable.

Response: The EPA evaluated this comment and belie ves that the reference to section 11 of Method 22 is appropriate and that referring to a number of different subsection s within section 11 would be unnecessarily complicated. Regarding the commenter’s statement on the use of a stopwatch, we believe that an y chronometer whose functionality includes that of a stopwatch would be permissible.53

2.5.3.7 Clarification of the Timing of Performance Testing

Comment: Two commenter s (4614 , 4631 ) request clarification on the timing of performance testing. The comment er s request that the language originally stated in the August 16, 2012 final rule be included with the date modified for Group 2 storage vessels as follows:

"You must conduct an initial performance test as required in § 60.5413 within 180 days

after initi al startup or within 180 days of April 15, 2014, whichever is later.”

According to the commenter ( 4631 ) , as the VOC emission rate determinations and reduction requirements for Group 2 storage vessels are not required until April 15, 2014, per § 60.5395(c)( 1), and (d)(1), respectively, it is not appropriate to require that an initial performance test be completed by the same date. ”

Response: Since field performance testing in not required in the final amendments, the

commenters’ concern is now moot.

2.5. 4 Compliance Monitoring Requirements

Comment: Two commenter s (4612 , 4626 ) provide support for the EPA’s proposed streamlined monitoring and continuous compliance demonstration requirements in lieu of the requirements currently containe d in the Oil and Gas NSPS. One c ommenter ( 4612 ) supports both the EPA's decision to reconsider the requirements contained in the final rule and also the EPA's proposal to replace those requirements, on an interim basis.

Response: The EPA thanks the commenters for their supp ort.

Comment: One commenter (4630) requests that the EPA add provisions for remote notification of open bypass devices at unmanned facilities.

Response: The final rule does not proscribe the use of remote notification of open bypass
devices. We understa nd that many of the facilities subject to the NSPS are unmanned and in remote locations. Thus, the owner or operator may install systems that allow remote notification, such as at a field office, for open bypass devices. We also note that the final amendme nts also allow records to be maintained at the nearest field office instead of maintaining the records
onsite.

Comment: One commenter (4611) requests that the EPA should clarify the definition of

“ no detectable emissions ” and its application to closed

- ve nt systems, including inspection requirements. S imilarly, this commenter requests that the EPA clarify what "leak free condition" means as stated in the requirements to demonstrate initial compliance with the enclosed combustion device requirements. The co mmenter is concerned that, since the EPA has not presented a definition of leak free condition for the operation of enclosed combustion devices, the discovery of a leak would mean an automatic violation, without regard for pending repair or

correction. The commenter asserted that, typically, discovery of a leak would trigger the source to repair or fix the leak within a prescribed timeframe, and the enforcing agency would consider these mitigating efforts in any noncompliance assessment.54

Response: In § 60. 5 411(c)(2) of the final amendments, we specify that closed vent systems must be design ed and operated with no detectable emissions as determined using an olfactory , visual and auditory (OVA) inspection. Therefore, a condition of no detectable

emissions woul d result when the OVA inspection revealed no leaks that were smelled, seen or heard during the inspection. Similarly, §60.5417(h) requires monthly OVA inspections of control devices, and operating in a leak free condition would mean that no leaks that were smelled, seen or heard during the inspection.

Comment: One commenter (46 11) requests that the EPA revise the proposed language to

reflect that AVO for closed vent systems be required for all oil and gas sites, but opined that requiring AVO alone would b e insufficient for production field facilities and gas processing plants , especially at facilities that include other processes and equipment subject to more extensive leak detection requirements

.

Response: In the preamble to the proposed amendments (see 78 FR 22134), we discussed issues raised by petitioners related to the compliance monitoring requirements and the burden these requirements placed on affected facilities in light of our revised estimate of the number of affected facilities. In response to these concerns, the EPA proposed certain streamlined monitoring and compliance demonstration requirements and we are finalizing the streamlined requirements in the final amendments. One aspect of the streamlined requirements is to require monthly AVO inspe ctions of covers, closed vent systems and control devices. In part, these AVO requirements replaced field testing requirements. The AVO requirements apply to storage vessels throughout the oil and natural gas production segment, natural gas processing segm ent and natural gas transmission and storage segment. We see no reason, nor does the commenter provide reasons, why the AVO methods would not be effective for storage vessels in production field facilities and gas processing plants

However, it appears tha t the commenter may be stating that the AVO methods may not be appropriate for equipment other than storage vessels at production field facilities and gas processing plants. We point out that the AVO requirements in the final amendments apply only

to stora ge vessels (and centrifugal compressors). The 2012 NSPS includes LDAR requirements for natural gas processing plants at §60.5400.

2. 5.5 Startup, Shutdown and Malfunction

Comment: One commenter (4630) reques ts that the EPA amend §60.5411(c)(3)(ii) to
inclu de a specific exemption for pressure relief valve safety devices so that it is clear they do not require a flow indicator and alarm required for bypasses . According to the commenter, the purpose of the pressure relief valve is to protect the integrity of t he storage vessel by allowing vapors to quickly exit the storage vessel and avoid an over

- pressure condition. The commenter states that a flow meter would restrict flow from the relief valve, which could compromise the storage vessel integrity and possibly result in catastrophic failure in a worst

- case scenario.

Response: We believe the pressure relief devices the commenter is referring to are conservation vent s

. It was not our intent to consider emissions from conservation vents on atmospheric storage ves sels subject to the NSPS to be bypasses. The conservation vent s on these55

storage vessels function to relieve both over

- pressure and under

- pressure situations that occur during normal operation of atmospheric storage vessels. This type of operation of the

c onservation vent is in contrast to a pressure relief device on a pressurized storage vessel in which a significant emissions event may occur when the pressure relief device opens and is designed to avoid a catastrophic failure of the storage vessel , which is the situation we intended for installation of flow indicators and alarms. We also note that the storage vessels subject to the NSPS are typically equipped with a weighted thief hatch in addition to a conservation vent . The

thief hatch will function to r elieve pressure to prevent a catastrophic failure of the storage vessel.

Comment: One commenter (4630) requests that the EPA clarify that certain features (e.g., sampling ports, when obtain in g material samples from the storage vessel, and pressure relief device s , when it is necessary to relieve exces s pressure) of the cover and closed vent

system have operational or safety related functions that are allowed to be open without having vapors routed through a closed vent system

.

Response: Sample ports woul d be subject to the cover requirements of §60.5411(b), which specify that each cover opening must be secured in a closed, sealed position when the opening is not in use (such as while obtaining a sample). The cover requirements in §60.5411(b) are designed to convey as much of the vapors as possible to the control device. Since these openings are subject to the cover requirements, we did not intend for them to also be vented through a closed vent system.

Comment: One commenter (4611) suggests that the EPA include monitoring and recordkeeping for downtime or the time that equipment is operating but the air pollution control equipment is not available.

Response: We note that the owner or operator is required to meet the control requirements of §60.5395(d) at all times, and we disagree that imposing additional monitoring and recordkeeping requirements beyond that specified in the final amendments are warranted. The final amendments also require certain monthly inspections of covers, closed vent systems

and con trol devices, and any abnormalities noted during these inspections must be recorded. We

believe th e se monthly inspections and the associated recordkeeping are sufficient for the situations presented in the comment.



### 2. 6 Compliance Schedule

Comment: Seve ral commen ters (4613, 4615, 4617, 4620) provide support for the EPA’s phased in approach to storage vessel requirements and proposed control installation date of April 15, 2014.

One commenter (4615) states that t he proposed control installation date of Ap ril 15,

2014

, for Group 2 storage vessels is consistent with the EPA’s recognition that sufficient control equipment won’t be available for the large number of storage vessels that will be subject to the

rule. The commenter asserts that s uch controls canno t be considered BSER until after a sufficient compliance time, i.e., April 15, 2014.56

Response: Please see section IV.B of the preamble to the final amendments for a discussion on the Group 2 compliance date in the final amendments.

Comment: Two commen ters (4613, 4623) request that the EPA provide for a streamlined process by which regulated entities can obtain an extension of the compliance date upon demonstration that controls are not available or reasonably available. One of the commenters (4623) sug gests that the EPA provide for a petition or other “exception” process.

Response: As explained in more detail in Sec ti on IV.A of the preamble to the final amendments, t he EPA has re

- analyzed the availability of control devices and , based on rationales

s et forth in that section, extended the compliance date in the 2012 NSPS to provide sufficient

time to obtain and install control devices . In light of the compliance deadlines in the final

amendments , we believe that a provision to allow further extension i s not needed. See section IV.A of the preamble to the final amendments for a discussion of control device availability.



### 2.7 Number of Storage Vessels at Different Throughput Levels (“Higher Emitting Storage Vessels ”)

Comment: T wo commenters (4615, 4630) opine that it is very difficult to provide information on the number of storage vessels with different potential VOC emissions due to the many variables that affect emissions

, such as throughput, separator temperature and pressure, and separator liquid com position and API gravity, especially given the time constraints of the comment period.

Two commenters (4615, 4630) state that the EPA has not defined “higher emitting” storage vessels ; however, they suggest that a storage vessel or a battery of storage vessels that can potentially emit more than t itle V major source threshold of 100 tpy VOC be considered “higher emitting storage vessels.” The commenter s provide that the EPA should not be overly concerned about the number of “higher emitting storage vesse ls” that may remain uncontrolled until April 15, 2014

, for the following reasons:

( 1) A ll “higher emitting storage vessels” are already subject to existing air permitting requirements. The commenter s explain that operators will typically install controls on any storage vessel or a battery of storage vessels with a potential to emit VOC above t itle V major

sourc e thresholds in order to avoid t itle V permitting if possible. The commenter s further explain that for storage vessels located at gathering station s and gas processing plants, there are other significant VOC emission sources located at the site such that the amount of VOC emitted from storage vessels is further limited if an operator wishes to avoid t itle V permitting. The

commenter states their beli ef that there will be few storage vessels or batteries of storage vessels prior to April 15, 2014

, that are emitting VOC above or near t itle V major source thresholds. ( 2) O perators will often install controls on storage vessels or a battery of storage ves sels in order to use a more streamlined state air permitting process. The commenter s explain that some states have minor source permits such as general permits or permits by rule with

limitations on total VOC emissions th at are significantly less than t itl e V major source thresholds. Therefore, the commenter s maintain that “higher emitting storage vessels” must be controlled in order to permit midstream facilities under th e general permits or permits by rule.57

The commenter s also state that some states may a pply BACT requirements in state general permits or permits by rule which may further limit the amount of VOC that can be emitted from storage vessels at permitted midstream facilities. (3) W hile there may be tens of thousands of Group 1 storage vessels ind ustry

- wide with potential uncontroll ed VOC emissions between 1 tpy and 50 tpy , there will not be that great a number of Group 1 storage vessels that are “higher emitting.” According to the commenter s
, the EPA does not need to require control for storage ve ssels with emissions above a certain level beyond t he 6 tpy threshold as existing t itle V major source permitting thresholds, and even lower state air permitting thresholds, have the effect of limiting emissions from storage vessels that

otherwise would be “higher emitting.”

Response: In the proposed rule, the EPA solicited comment on the number of storage vessels at different throughput levels (or VOC emission levels) to further inform our consideration of controlling higher emitting storage vessels earl ier than April 15, 2014. We thank the commenters for the information provided

. However, no substantive data on the number of higher emitting storage vessels was provided, and we decided to take another approach. Based on our recent understanding of the sup ply of control devices and concerns related to how quickly the combustor industry can ramp up production, we decided to take a phased

- in approach that requires the newer affected facilities (which would have higher emissions) to comply first. Since this ap proach would, we believe, effectively control the higher emitting storage vessels first, we no long e r had need to estimate the number of higher emitting storage vessels.



### 2.8 Small Business Impacts

Comment: One commenter (4634) provides that the EPA indic ates

, on page 22137 of the proposal published in the April 12, 2013, issue of the Federal Register , there will be no significant compliance costs as a result of this proposed rule because "owners and operators of storage vessel affected facilities would in stall the same or similar control technologies as they would have installed to comply with the previously finalized standards." The commenter states

that the EPA further indicates that it has certified that the proposed action will not have significant eco nomic impact on a substantial number of small entities. After stating that it considered the economic impact of the proposed NSPS on small entities, the commenter states

that the EPA certified that the proposed NSPS would not have a significant economic im pact on a substantial number of small entities, based on the EPA's conclusion that many affected firms are expected to receive revenues from the additional natural gas and condensate recovery resulting from certain emissions controls, particularly those fo r completion

- related activities and vapor recovery units on storage vessels. According to the commenter, m ost crude oil producers, particularly operators of stripper crude oil wells, will not realize this benefit. The commenter provides that, as they comme nted in their letter dated October 25, 2011, to the EPA's proposed rules published in the August 23, 2011, issue of the Federal Register (76 FR 52738), the y believe the EPA greatly underestimated the negative impact of compliance with the rule on small

bus inesses. The commenter states that their review indicates that the EPA did not respond to this specific comment submitted to the EPA in their 2011 comment letter and they request that the EPA respond to their comment concerning impacts to small businesses.

Response: The comments related to the impacts of the 2012 NSPS were addressed in that rulemaking. See Response to Public Comments on Proposed Rule, August 23, 2011 (76 FR58

52738) , which is available in the docket. However, although the number of storage vessel affected facilities is greater than initially estimated in the 2012 NSPS, we believe that changes we are finalizing in this rule, such as streamlined compliance monitoring, will provide relief to industry, including relief to small business entities and operators of stripper crude oil wells. As noted in section V.C of the preamble to the final amendments, the Group 1 compliance date we have adopted addresses our concern about how a potential shortage of trained personnel may impact small businesses a s comments we received indicate that larger owners and operators may be able to garner the majority of the available installation personnel due to their greater resources. This may result in a situation where small owners and operators may be placed in a

c ompetitive disadvantage in obtaining installation personnel. If such a situation should occur, the smaller owners and operators may be forced to shut down wells or delay drilling new wells until installation personnel are made available. In light of concer ns such as these, we adopted the phased

- in approach described in the preamble to the final amendments, which would enable sources more time to plan and acquire the necessary equipment and labor needed.

Comment: One commenter (4634) reports that t he EPA d oes not consider impacts of the proposed regulations on stripper wells

. According to the commenter, i n order to lessen the burden on these operators (of stripper wells) and maintain production of the s tate's valuable

resources, they strongly urge the EPA t o provide a pathway by which such wells could exit the requirements of the rules. According to the commenter, t he proposed regulations for storage vessels for crude oil and produced water associated with crude oil do not consider impacts of the proposed re gulations on stripper wells. The commenter provides that a "stripper well" is a well that produces crude oil at very low rates. The commenter reports that the Interstate Oil & Gas Compact Commission defines a stripper oil well as one that produces less tha n 10 barrels of oil per day.

The commenter (4634) reports that s tripper oil wells represent a significant portion of the

total number of oil wells. The commenter states that the United States Department of Energy

estimates that in 2009 there were over 28 6,000 of these wells in the United States and that together they produced over 217 million barrels of oil (see http://www.eia.gov/pub/oilgas/petrosystemlustable.html (accessed May 22, 201 3). The

commenter refers to a table included as an attachment to their comments dated October 25, 2011, entitled "Texas 2009 Distribution of Wells by Production Rate Bracket," which indicates that almost 80 percent of all Texas oil wells produced less than or equal to 10 barrels of crude oil per day in 2009. According to the commenter, t he production from those wells accounted for 30 percent of Texas' annual oil production. The commenter reports that, a lthough the average per well production was 2.4 barrels of oil per day, many of these stripper wells are connected to lease tank batteries that include storage vessels, such as crude oil vessels, produced water vessels, and treating/separation vessels. The commenter states that a majority of these stripper

wel ls are owned and operated by small businesses that are families, not "firms." According to the

commenter, t he only business in which many of these small bu sinesses engage in Texas is the operation of stripper oil wells. However, the commenter provides that in the EPA’s analysis of economic impact, the EPA included this group of small entities with all small businesses engaged in the activities encompassed by the proposed rules, thereby diluting the impact on stripper oil well oper ators. Therefore, the comme nter believes that the economic impact analysis fails to adequately demonstrate the full impact on this category of small businesses in Texas and59

many other states with a high percentage of stripper oil wells and a high percentage of family operations.

T he commenter (4634) provides that w hile the EPA proposes to adopt a threshold below which storage vessels would not be subject to the requirements of the proposed rule, operators of stripper wells still would be required to expend their limited funds to ma ke such a determination. The commenter requests that, i n order to lessen the economic burden on these operators and maintain production of the State's valuable natural resources, the EPA develop a tool, such as a reference table, by which these stripper we ll operators can more economically determine whether or not they are above or below the 6 tpy threshold, using readily available information, such as throughput volumes, type of hydrocarbon, and API gravity. In addition, the commenter state s that, because the proposed regulations are structured such that, once regulated always regulated, a crude oil well that becomes a stripper well at some point in the future, still would be required to monitor, verify, and report emissions as required by the proposed regu lations, increasing the risk of valuable state resources being unproduced. Again, in order to lessen the burden on these operators and maintain production of th e s tate's valuable resources, the commenter urge s the EPA to provide a pathway by which such wel ls could exit the requirements of the rules.

Response: We included stripper wells in our analysis of the number of potentially affected storage vessels supporting this action. Regarding the commenter’s inclusion of Interstate Oil & Gas Compact Commission’ s definition of a stripper oil well as one that produces less than 10 barrels of oil per day, we have determined that the storage vessel VOC emissions for such a

well would be approximately 2 tpy, which is below the 6 tpy VOC emissions threshold.

Additiona lly, only stripper wells constructed on or after August 23, 2011, may be subject to the rule and, as shown, it is unlikely that many will be subject to the rule because of the low production rates of these wells. Additionally, for affected storage vessels, once operators have demonstrated that the uncontrolled actual VOC emissions have remained less than 4 tpy for 12 consecutive months, the operator may maintain the uncontrolled actual VOC emissions from the storage vessel affected facility at less than 4 t py, resulting in reduced burden.

As stated in the preamble to the final amendments, we expect that owners and operators of storage vessel affected facilities would install the same or similar control technologies to meet

the standards finalized in this a ction, as they would have chosen to comply with the 2012 NSPS

. Therefore, we do not anticipate that th e final amendments will result in significant changes in costs, benefits or economic impacts compared to the req u irements in the 2012 NSPS. As such,

we ha ve certified that this action will not have a significant economic impact on a substantial

number of small entities.

Regarding the development of a tool to assist stripper well operators to more economically determine whether or not they are above or belo w the 6 tpy threshold, the EPA does not limit the methodologies operators can use to determine their emissions. There are several tools currently available to owners and operators (see section 2.1.2.6) and it is up to each owner or operator to choose the m ost cost

- effective tool for their operation. Therefore, we believe that operators can determine their emissions with relatively low effort, even for operators of stripper wells. We do not believe it is necessary or desirable for the EPA to create an

additi onal tool.