Vol. 79 Wednesday, 

No. 250 December 31, 2014 

Part III 

Environmental Protection Agency 

40 CFR Part 60 

Oil and Natural Gas Sector: Reconsideration of Additional Provisions of 

New Source Performance Standards; Final Rule 


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ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 60 

[EPA–HQ–OAR–2010–0505; FRL–9921–03– 

OAR] 

RIN 2060–AR75 

Oil and Natural Gas Sector: 

Reconsideration of Additional 

Provisions of New Source 

Performance Standards 

AGENCY: Environmental Protection 

Agency. 

ACTION: Final rule. 

SUMMARY: This action finalizes 

amendments to new source performance 

standards (NSPS) for the oil and natural 

gas sector. On August 16, 2012, the 

Environmental Protection Agency (EPA) 

published final NSPS for the oil and 

natural gas sector. The Administrator 

received petitions for administrative 

reconsideration of certain aspects of the 

standards. Among issues raised in the 

petitions were time-critical issues 

related to certain storage vessel 

provisions and well completion 

provisions. On July 17, 2014 (79 FR 

41752), the EPA published proposed 

amendments and clarifications as a 

result of reconsideration of certain 

issues related to well completions, 

storage vessels and other issues raised 

for reconsideration as well as technical 

corrections and amendments to further 

clarify the rule. This action finalizes 

these amendments and corrects 

technical errors that were inadvertently 

included in the final standards. 

DATES: This final rule is effective on 

December 31, 2014. 

ADDRESSES: The EPA has established a 

docket for this action under Docket ID 

No. EPA–HQ–OAR–2010–0505. All 

documents in the docket are listed in 

the http://www.regulations.gov index. 

Although listed in the index, some 

information is not publicly available, 

e.g., confidential business information 

(CBI) or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the internet and will be publicly 

available only in hard copy. Publicly 

available docket materials are available 

either electronically through http://

www.regulations.gov or in hard copy at 

the EPA’s Docket Center, Public Reading 

Room, EPA WJC West Building, Room 

Number 3334, 1301 Constitution 

Avenue NW., Washington, DC 20004. 

This docket facility is open from 8:30 

a.m. to 4:30 p.m., Monday through 

Friday, excluding legal holidays. The 

telephone number for the Public 

Reading Room is (202) 566–1744, and 

the telephone number for the Air Docket 

is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: Mr. 

Bruce Moore, Sector Policies and 

Programs Division (E143–05), Office of 

Air Quality Planning and Standards, 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711, telephone number: (919) 541– 

5460; facsimile number: (919) 685–3200; 

email address: moore.bruce@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Organization of This Document. The 

information presented in this preamble 

is organized as follows: 

I. Preamble Acronyms and Abbreviations 

II. General Information 

A. Executive Summary 

B. Does this reconsideration action apply 

to me? 

C. How do I obtain a copy of this document 

and other related information? 

D. Judicial Review 

III. Summary of Final Amendments 

A. Well Completions 

B. Storage Vessels 

C. Routing of Reciprocating Compressor 

Rod Packing Emissions to a Process 

D. Equipment Leaks at Gas Processing 

Plants 

E. Definition of ‘‘Responsible Official’’ 

F. Affirmative Defense 

IV. Summary of Significant Changes since 

Proposal 

A. Well Completions 

B. Storage Vessels 

C. Definition of ‘‘Responsible Official’’ 

V. Summary of Significant Comments and 

Responses 

A. Well Completions 

B. Storage Vessels 

C. Routing of Reciprocating Compressor 

Rod Packing Emissions to a Process 

VI. Technical Corrections and Clarifications 

VII. Impacts of These Final Amendments 

A. What are the air impacts? 

B. What are the energy impacts? 

C. What are the compliance costs? 

D. What are the economic and employment 

impacts? 

E. What are the benefits of the final 

standards? 

VIII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act (PRA) 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act of 1995 

(UMRA) 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination with Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations that 

Significantly Affect Energy Supply, 

Distribution or Use 

I. National Technology Transfer and 

Advancement Act (NTTAA) 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act (CRA) 

I. Preamble Acronyms and 

Abbreviations 

Several acronyms and terms are 

included in this preamble. While this 

may not be an exhaustive list, to ease 

the reading of this preamble and for 

reference purposes, the following terms 

and acronyms are defined here: 

CAA Clean Air Act 

CFR Code of Federal Regulations 

CO2 Carbon Dioxide 

EPA Environmental Protection Agency 

LEL Lower Explosive Limit 

NSPS New Source Performance Standards 

NTTAA National Technology Transfer and 

Advancement Act 

OAQPS Office of Air Quality Planning and 

Standards 

OMB Office of Management and Budget 

PTE Potential to Emit 

psi Pounds per Square Inch 

REC Reduced Emissions Completion 

RFA Regulatory Flexibility Act 

tpy Tons per Year 

UMRA Unfunded Mandates Reform Act 

VOC Volatile Organic Compounds 

VRU Vapor Recovery Unit 

II. General Information 

A. Executive Summary 

1. Purpose of This Regulatory Action 

The purpose of this action is to 

finalize amendments to the 40 CFR part 

60, subpart OOOO, Standards of 

Performance for Crude Oil and Natural 

Gas Production, Transmission and 

Distribution final rule promulgated 

under section 111(b) of the Clean Air 

Act (CAA), which was published on 

August 16, 2012 (77 FR 49490). 

Specifically, this final rule addresses 

certain issues related to well completion 

and storage vessel provisions that have 

been raised by different stakeholders 

through several administrative petitions 

for reconsideration of the 2012 NSPS 

and the 2013 storage vessel amendments 

to the NSPS. The EPA is amending the 

NSPS to address these issues. Proposed 

amendments were published on July 17, 

2014. (79 FR 41752) 

2. Summary of Major Amendments to 

the NSPS 

We are amending the standards for 

gas well affected facilities to provide 

greater clarity concerning what owners 

and operators must do during well 

completion operations with respect to 

the handling of gas and liquids during 

the well completion operations. In this 

action, we clarify that the flowback 


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period of a well completion following 

hydraulic fracturing consists of two 

distinct stages, the ‘‘initial flowback 

stage’’ and the ‘‘separation flowback 

stage.’’ The initial flowback stage begins 

with the onset of flowback and ends 

when the flow is routed to a separator. 

During the initial flowback stage, any 

gas in the flowback is not subject to 

control. However, the operator must 

route the flowback to a separator unless 

it is technically infeasible for a separator 

to function. The point at which the 

separator can function marks the 

beginning of the separation flowback 

stage. During this stage, the operator 

must route all salable quality gas from 

the separator to a flow line or collection 

system, re-inject the gas into the well or 

another well, use the gas as an on-site 

fuel source or use the gas for another 

useful purpose. If it is infeasible to route 

the gas as described above, or if the gas 

is not of salable quality, the operator 

must combust the gas unless 

combustion creates a fire or safety 

hazard or can damage tundra, 

permafrost or waterways. No direct 

venting of gas is allowed during the 

separation flowback stage. The 

separation flowback stage ends either 

when the well is shut in and the 

flowback equipment is permanently 

disconnected from the well, or on 

startup of production. This also marks 

the end of the flowback period. The 

operator has a general duty to safely 

maximize resource recovery and 

minimize releases to the atmosphere 

over the duration of the flowback 

period. The operator is also required to 

document the stages of the completion 

operation by maintaining records of (1) 

the date and time of the onset of 

flowback; (2) the date and time of each 

attempt to route flowback to the 

separator; (3) the date and time of each 

occurrence in which the operator 

reverted to the initial flowback stage; (4) 

the date and time of well shut in; and 

(5) date and time that temporary 

flowback equipment is disconnected. 

The NSPS already requires that the 

operator document the total duration of 

venting, combustion and flaring over the 

flowback period. All flowback liquids 

during the initial flowback period and 

the separation flowback period must be 

routed to a well completion vessel, a 

storage vessel or a collection system. On 

startup of production, the operator must 

begin the 30-day process of estimating 

the volatile organic compound (VOC) 

potential to emit (PTE) for storage 

vessels that will receive the liquids from 

the well. If the PTE is at least 6 tons/ 

yr (tpy), the operator must control 

emissions from the storage vessel no 

later than 60 days after the startup of 

production (for storage vessels used in 

applications other than production 

following well completions, the term 

used to identify this point in time is 

‘‘startup’’). A well completion vessel to 

which liquids from the well are routed 

after startup of production for a period 

in excess of 60 days is considered a 

‘‘storage vessel’’ subject to the storage 

vessel PTE determination and, if 

determined to be a storage vessel 

affected facility, would be subject to the 

control, cover and closed vent system 

requirements of the NSPS. 

We are finalizing the definition of 

‘‘low pressure gas well,’’ as presented in 

the 2012 NSPS and re-proposed in the 

July 17, 2014, proposed rule. 

We are finalizing several amendments 

related to the storage vessel provisions 

of the NSPS. First, we are finalizing 

provisions for determining VOC PTE for 

storage vessels with vapor recovery to 

clarify that the provisions allowing 

sources to exclude emissions captured 

through vapor recovery if certain 

specified control requirements are met 

do not apply to storage vessels whose 

PTE is limited to below the 6 tpy 

applicability threshold under a legally 

and practically enforceable permit or 

other limitation under federal, state or 

tribal authority. We are also amending 

the storage vessel closed vent system 

and cover requirements to allow use of 

other mechanisms besides weighted lid 

thief hatches to ensure that the thief 

hatch lid remains properly seated. In 

addition, we are amending the 

requirements for storage vessels to 

clarify notification and other 

requirements under the NSPS for 

storage vessels affected facilities that are 

removed from service for reasons other 

than maintenance. Further, we are 

clarifying that Group 1 and Group 2 

storage vessel affected facilities that are 

removed from service are no longer 

affected facilities and therefore have no 

requirements under the NSPS until they 

are returned to service. The status of a 

Group 1 or Group 2 storage vessel that 

is later returned to service depends on 

its new use, which can fall into three 

possible scenarios. If the storage vessel 

is used to replace a storage vessel 

affected facility, or is being connected in 

parallel with a storage vessel affected 

facility, it is immediately subject to the 

same requirements as the affected 

facility being replaced or with which it 

is being connected in parallel. If the 

vessel is not used to replace or 

connected in parallel with an affected 

facility but is being used to contain 

crude oil, condensate, intermediate 

hydrocarbon liquids or produced water, 

it is allowed 30 days to determine if its 

VOC PTE is at least 6 tpy, and if so is 

subject to the requirements for Group 2 

storage vessel affected facilities and 

would be required to control emissions 

no later than 60 days after return to 

service. If the vessel is being used in an 

application other than to contain crude 

oil, condensate, intermediate 

hydrocarbon liquids or produced water, 

it does not meet the definition of 

‘‘storage vessel’’ and is not an affected 

facility under the NSPS. 

We are amending the requirements for 

reciprocating compressors to add a third 

alternative to the two existing work 

practice options for controlling 

emissions from rod packing venting. We 

are finalizing a third alternative that 

would allow routing emissions from the 

rod packing through a collection system 

under negative pressure via a closed 

vent system to a process. 

We are finalizing two amendments to 

the equipment leaks requirements for 

natural gas processing plants. One is to 

correct an inadvertent omission we 

made in the 2012 NSPS concerning an 

exemption from routine leak detection 

in small gas processing plants and gas 

processing plants located on the 

Alaskan North Slope. In addition, we 

are amending the definition of 

‘‘equipment’’ to clarify that the term, as 

used in relation to the equipment leaks 

requirements under the NSPS, refers 

only to equipment at onshore natural 

gas processing plants. 

We are amending the provisions 

related to ‘‘responsible official’’ to 

remove any confusion by the regulated 

community with respect to the 

requirements for certifying under 

subpart OOOO and references to 

‘‘responsible official’’ under the title V 

permitting program. To that end, we are 

changing the term ‘‘responsible official’’ 

to ‘‘certifying official.’’ We are also 

finalizing the proposed amendments to 

provide for delegation of authority after 

advance notification for facilities that 

employ 250 or fewer employees and 

have less than $25 million gross annual 

sales or expenditures (in second quarter 

1980 dollars). 

Finally, the EPA is removing a 

regulatory affirmative defense provision 

from the rule. If a source is unable to 

comply with emissions standards as a 

result of a malfunction, the EPA may 

use its case-by-case enforcement 

discretion to provide flexibility, as 

appropriate. 

3. Cost and Benefits 

Our analysis shows that owners and 

operators of affected facilities would 

choose to install and operate the same 

or similar air pollution control 

technologies under these amended 


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standards as would have been necessary 

to meet the previously finalized 

standards. We project that this rule will 

result in no significant change in costs, 

emission reductions or benefits. Even if 

there were changes in costs for these 

units, such changes would likely be 

small relative to both the overall costs 

of the individual projects and the 

overall costs and benefits of the final 

rule. Since we believe that owners and 

operators would put on the same or 

similar controls for this final rule that 

they would have for the original final 

rule, there should not be any 

incremental costs related to this final 

revision. 

B. Does this reconsideration action 

apply to me? 

Categories and entities potentially 

affected by today’s action include: 

TABLE 1—INDUSTRIAL SOURCE CATEGORIES AFFECTED BY THIS ACTION

Category NAICS code 1 Examples of regulated entities 

Industry ..................................................... 211111 Crude Petroleum and Natural Gas Extraction. 

211112 Natural Gas Liquid Extraction. 

221210 Natural Gas Distribution. 

486110 Pipeline Distribution of Crude Oil. 

486210 Pipeline Transportation of Natural Gas. 

Federal government .................................. ........................ Not affected. 

State/local/tribal government .................... ........................ Not affected. 

1 North American Industry Classification System. 

This table is not intended to be 

exhaustive, but rather is meant to 

provide a guide for readers regarding 

entities likely to be affected by this 

action. If you have any questions 

regarding the applicability of this action 

to a particular entity, consult either the 

air permitting authority for the entity or 

your EPA regional representative as 

listed in 40 CFR 60.4 (General 

Provisions). 

C. How do I obtain a copy of this 

document and other related 

information? 

In addition to being available in the 

docket, electronic copies of the final and 

proposed rules will be available on the 

WorldWide Web. Following signature, a 

copy of the rule will be posted at the 

following address: http://www.epa.gov/

airquality/oilandgas/actions.html. 

D. Judicial Review 

Under section 307(b)(1) of the CAA, 

judicial review of this final rule is 

available only by filing a petition for 

review in the United States Court of 

Appeals for the District of Columbia 

Circuit by March 2, 2015. Under section 

307(d)(7)(B) of the CAA, only an 

objection to this final rule that was 

raised with reasonable specificity 

during the period for public comment 

can be raised during judicial review. 

Moreover, under section 307(b)(2) of the 

CAA, the requirements established by 

this final rule may not be challenged 

separately in any civil or criminal 

proceedings brought by the EPA to 

enforce these requirements. Section 

307(d)(7)(B) of the CAA further provides 

that ‘‘[o]nly an objection to a rule or 

procedure which was raised with 

reasonable specificity during the period 

for public comment (including any 

public hearing) may be raised during 

judicial review.’’ This section also 

provides a mechanism for us to convene 

a proceeding for reconsideration, ‘‘[i]f 

the person raising an objection can 

demonstrate to the EPA that it was 

impracticable to raise such objection 

within [the period for public comment] 

or if the grounds for such objection 

arose after the period for public 

comment (but within the time specified 

for judicial review) and if such objection 

is of central relevance to the outcome of 

the rule.’’ Any person seeking to make 

such a demonstration to us should 

submit a Petition for Reconsideration to 

the Office of the Administrator, U.S. 

EPA, Room 3000, William Jefferson 

Clinton West Building, 1200 

Pennsylvania Ave. NW., Washington, 

DC 20460, with a copy to both the 

person(s) listed in the preceding FOR

FURTHER INFORMATION CONTACT section, 

and the Associate General Counsel for 

the Air and Radiation Law Office, Office 

of General Counsel (Mail Code 2344A), 

U.S. EPA, 1200 Pennsylvania Ave. NW., 

Washington, DC 20460. 

III. Summary of Final Amendments 

This section presents a summary of 

the provisions of the final action with 

brief explanations where appropriate. In 

some cases additional, detailed 

discussions are provided in sections IV 

or V. The final amendments include 

revisions to certain reconsidered aspects 

of the existing 2012 NSPS as follows: (1) 

Provisions for well completions that 

clarify and amend existing requirements 

for handling of flowback gases and 

liquids; (2) definition of ‘‘low pressure 

gas well’’; (3) requirements pertaining to 

determining the potential emissions 

from storage vessels; (4) requirements 

for thief hatches; (5) provisions for 

storage vessels that are removed from 

service and for those that are returned 

to service; (6) provisions for routing of 

emissions from reciprocating 

compressor rod packing to a process; (7) 

leak detection requirements at small 

natural gas processing plants and 

natural gas processing plants located on 

the Alaskan North Slope; (8) 

clarification of equipment subject to 

leak detection requirements under the 

NSPS; and (9) revised definition of 

‘‘responsible official’’ and revision of 

the term to be ‘‘certifying official’’ for 

compliance certification purposes. In 

addition, we are removing the 

affirmative defense provisions from the 

startup, shutdown and malfunction 

provisions of the 2012 NSPS and are 

correcting technical errors in the 2012 

NSPS. A summary of the final 

amendments resulting from our 

reconsideration is provided in the 

following paragraphs. 

A. Well Completions 

1. Handling of Flowback Gases and 

Liquids 

In today’s action we are finalizing 

requirements in § 60.5375 for handling 

of gases and liquids during flowback. 

The regulatory language in the well 

completion provisions of § 60.5375 is 

amended to identify two distinct stages 

associated with well completion, with 

each stage having specific requirements 

for handling of gases and liquids. The 

final provisions are changed slightly 

from the proposed amendments in 

response to public comments. 

Discussion of our rationale for these 

changes since proposal are presented in 

section IV.A. 

The flowback period consists of two 

stages, the ‘‘initial flowback stage’’ and 

the ‘‘separation flowback stage.’’ The 

initial flowback stage begins with the 


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first flowback from the well following 

hydraulic fracturing or refracturing and 

is characterized by high volumetric flow 

water, containing sand, fracturing fluids 

and debris from the formation with very 

little gas being brought to the surface, 

usually in multiphase slug flow. During 

this stage, the flowback must be routed 

to a ‘‘storage vessel’’ or to a ‘‘well 

completion vessel’’ that can be a frac 

tank, a lined pit or any other vessel. Our 

reason for this requirement is to avoid 

having operators route the flowback to 

an unlined pit or onto the ground. 

During the initial flowback stage, there 

is no requirement for controlling 

emissions from the vessel, and any gas 

in the flowback during this stage may be 

vented. However, the operator must 

route the flowback to a separator unless 

it is technically infeasible for a separator 

to function. As a result, we have 

changed ‘‘as soon as sufficient gas is 

present in the flowback for a separator 

to operate’’ to ‘‘unless it is technically 

infeasible for a separator to function.’’ 

We stress that operators have the 

responsibility to direct the flowback to 

a separator as soon as conditions allow 

a separator to function and in 

accordance with the General Provision 

requirements to operate the affected 

facility in a manner consistent with 

good air pollution control practices for 

minimizing emissions. 

The second stage is defined as the 

‘‘separation flowback stage.’’ The point 

at which the separator can function 

marks the beginning of the separation 

flowback stage. This stage is 

characterized by the separator operating 

with a gaseous phase and one or more 

liquid phases in the separator. During 

this stage, the operator must route all 

salable quality gas from the separator to 

a gas flow line or collection system, reinject the gas into the well or another 

well, use the gas as an on-site fuel 

source or use the gas for another useful 

purpose that a purchased fuel or raw 

material would serve. If, during the 

separation flowback stage, it is 

infeasible to route the recovered gas to 

a flow line or collection system, reinject 

the gas or use the gas as fuel or for other 

useful purpose, the recovered gas must 

be combusted. No direct venting of 

recovered gas is allowed during the 

separation flowback stage except when 

combustion creates a fire or safety 

hazard or can damage tundra, 

permafrost or waterways. With regard to 

infeasibility of collecting the salable 

quality gas, we believe that owners and 

operators plan their operations to 

extract a target product and evaluate 

whether the appropriate infrastructure 

access is available to ensure their 

product has a viable path to market 

before completing a well. However, 

there may be isolated cases in which, for 

reason(s) not within an operator’s 

control, the well is completed and 

flowback occurs without a suitable flow 

line available. In those isolated 

instances, the NSPS provides a solution 

in § 60.5375(a)(3), which requires 

combustion of the gas unless 

combustion poses an unsafe condition 

as described above. During the 

separation flowback stage, all liquids 

from the separator must be directed to 

a storage vessel or to a well completion 

vessel, routed to a collection system or 

be re-injected into the well or another 

well. 

The end of the separation flowback 

stage marks the end of the flowback 

period and is defined as the point at 

which the well is shut in and the 

flowback equipment is permanently 

disconnected from the well, or the 

startup of production. Identification of 

this point is discussed in detail in 

section IV.A. As provided in the 2012 

NSPS, the operator has a general duty to 

safely maximize resource recovery and 

minimize releases to the atmosphere 

over the duration of the flowback 

period. 

At some point following the end of 

the flowback period, depending on how 

long the well is shut in (if shut in), 

startup of production will occur. 

Depending on the situation, the operator 

may choose to startup production 

immediately following the end of 

flowback, once the well is temporarily 

shut in to remove flowback equipment, 

may begin production without shutting 

in and removing flowback equipment, 

or the operator might delay startup for 

some period of time by leaving the well 

shut in until permanent production 

equipment has been installed. Startup of 

production, whenever that occurs, 

marks the beginning of the 30-day 

period for determining VOC PTE for 

purposes of making a storage vessel 

affected facility determination in 

accordance with the procedure in 

§ 60.5365(e). If the criteria in 

§ 60.5365(e) are met, the operator would 

have to comply with the control 

requirements in § 60.5395(d)(1) within 

60 days after the startup of production. 

During this period, any recovered 

liquids must be routed to well 

completion vessels, storage vessels or a 

collection system. A well completion 

vessel to which liquids are routed from 

the well for a period in excess of 60 

days after startup of production would 

be considered a ‘‘storage vessel’’ under 

the NSPS and, depending on its VOC 

PTE, would be subject to the control, 

cover and closed vent system 

requirements for storage vessel affected 

facilities. We are finalizing amendments 

to § 60.5365(e) to reflect that, for storage 

vessels associated with production 

following completions, the 30-day 

period for the affected facility 

determination required § 60.5365(e) 

commences on startup of production. 

We are also amending the requirements 

for storage vessel affected facilities in 

§ 60.5395(d)(1)(i) to reflect that, for 

purposes of the well completion 

provisions, control is required no later 

than 60 days from startup of production. 

To accompany these changes, we are 

also amending the reporting and 

recordkeeping requirements in 

§ 60.5420 to revise the terminology used 

in that section relating to periods of gas 

recovery, combustion and venting to be 

compatible with the terms used in the 

final clarifying amendments to 

§ 60.5375, including addition of a 

requirement to document the time of the 

beginning of flowback, the time at 

which the operator directs the flowback 

to a separator (each time this is done), 

the reason for reverting back to the 

initial flowback stage (if this is done), 

the time of well shut in and removal of 

flowback equipment (end of the 

flowback period) and time of startup of 

production (beginning of the PTE 

determination period). We are also 

revising the language used in 

requirements for exploratory, 

delineation and low pressure wells in 

§ 60.5375(f) to be consistent with the 

final amended terminology and 

requirements in § 60.5375(a). 

2. Definition of ‘‘Low Pressure Gas 

Well’’ 

We are finalizing the re-proposed 

2012 EPA definition of ‘‘low pressure 

gas well’’ without change. This 

definition is used in conjunction with 

§ 60.5375(f), which provides that those 

wells for which a reduced emissions 

completion (REC) would not be feasible 

because of a combination of well depth, 

reservoir pressure and flow line 

pressure is not required to meet the 

requirements for recovery of gases and 

liquids required under § 60.5375(a). 

Instead of having to perform an REC and 

recover gas during the separation 

flowback stage, operators performing 

completions of low pressure gas wells 

(in addition to wildcat wells and 

delineation wells) are required only to 

combust the gas rather than capture it 

during flowback. The 2012 NSPS 

included a definition of ‘‘low pressure 

gas well’’ in the final rule that is based 

on a mathematical formula that takes 

into account a well’s depth, reservoir 

pressure and flow line pressure. The 


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1Email from James D. Elliott, Spilman, Thomas 

& Battle PLLC, to Bruce Moore, EPA, March 24, 

2014. 

definition of ‘‘low pressure gas well’’ is 

found in § 60.5430. 

Following publication of the final 

rule, several petitioners for 

administrative reconsideration 

(hereinafter ‘‘petitioners’’) questioned 

the technical merits of the low pressure 

well definition and asserted that the 

public had not had an opportunity to 

comment on the definition because it 

was added in the final rule. In the July 

17, 2014, proposed rule, we re-proposed 

the 2012 definition and solicited 

comment on an alternative definition 

provided by these petitioners.1 For the 

reasons discussed in detail in section 

V.A, we are retaining the 2012 

definition without change. 

B. Storage Vessels 

On September 23, 2013, the EPA 

published amendments primarily 

focused on storage vessel 

implementation issues raised by 

petitioners following publication of the 

2012 final NSPS. Following publication 

of the 2013 storage vessel amendments, 

three petitioners filed additional 

administrative reconsideration 

petitions, in which they raised issues 

with regard to various provisions of the 

2013 amendments. Among these issues 

are requirements for determining PTE 

for storage vessels employing vapor 

recovery under a legal and practically 

enforceable limitation, requirement for 

thief hatches being properly seated and 

clarification of the term ‘‘storage vessels 

removed from service.’’ 

1. PTE Determination for Storage 

Vessels Employing Vapor Recovery 

Under a Legally and Practically 

Enforceable Limitation 

We are finalizing amendments to 

§ 60.5365(e) to allow the PTE exclusion 

provision only in cases where a storage 

vessel is not subject to any legally and 

practically enforceable limitation or 

other requirement under a federal, state, 

local or tribal authority. An owner or 

operator invoking this exclusion 

provision must comply with the 

provisions of § 60.5365(e)(1) through (4) 

in determining VOC PTE for purposes of 

determining affected facility status. 

2. Thief Hatch Properly Seated 

We are finalizing amendments to 

§ 60.5411(b)(3) to require that thief 

hatches be equipped, maintained and 

operated with a weighted mechanism or 

equivalent, to ensure that the lid 

remains properly seated. This 

amendment provides for proper seating 

of thief hatch lids while allowing 

innovation and flexibility in design not 

afforded by requiring that thief hatch 

lids be weighted. 

3. Storage Vessels Removed From 

Service 

As proposed, we are amending 

§ 60.5395(f)(1) and (2), and 

§ 60.5420(b)(6), to require that the dates 

that storage vessel affected facilities are 

removed from service and returned to 

service be included when reporting 

those actions. 

For the reasons discussed in detail in 

section IV.B, we are also amending the 

NSPS to clarify that a Group 1 and 

Group 2 storage vessel affected facility 

that is removed from service, which is 

defined in § 60.5430 as physically 

isolated and disconnected from the 

process for a purpose other than 

maintenance and, pursuant to 

§ 60.5395(f)(1), completely emptied and 

degassed and no longer used to contain 

crude oil, condensate, produced water 

or intermediate hydrocarbon liquids, 

would no longer meet the definition of 

‘‘storage vessel’’ in § 60.5430 and, 

therefore, cease to be affected facilities 

under the NSPS for the period they are 

out of service. 

We are also amending the NSPS to 

provide that a Group 1 or Group 2 

storage vessel affected facility that is 

returned to service is subject to the 

NSPS based on the use of the vessel in 

its new application. There are three 

possible scenarios for vessels returned 

to service: (1) The vessel is used to 

replace a storage vessel affected facility 

or is connected in parallel with a storage 

vessel affected facility; (2) the vessel is 

not used to replace an affected facility 

but is being used to contain crude oil, 

condensate, intermediate hydrocarbon 

liquids or produced water; or (3) the 

vessel is being used in an application 

other than to contain crude oil, 

condensate, intermediate hydrocarbon 

liquids or produced water. If the vessel 

is being used to replace a storage vessel 

affected facility or is connected in 

parallel with a storage vessel affected 

facility (i.e., the liquid contents and the 

VOC PTE are already known), then it is 

a storage vessel affected facility and 

immediately upon startup would be 

subject to the same requirements as the 

storage vessel affected facility being 

replaced. If the vessel is not being used 

to replace an affected facility but is 

being used to contain crude oil, 

condensate, intermediate hydrocarbon 

liquids or produced water (i.e., the VOC 

PTE is unknown), then, just as for any 

new storage vessel, the operator would 

be afforded a 30-day period after startup 

to determine the storage vessel’s 

affected facility status based on VOC 

PTE and, if VOC PTE were estimated to 

be at least 6 tpy, the storage vessel 

would be determined an affected facility 

and would be subject to requirements 

for Group 2 storage vessels, and 

controlled no later than 60 days after 

startup. If the vessel is not being used 

to contain crude oil, condensate, 

intermediate hydrocarbon liquids or 

produced water, it does not meet the 

definition of ‘‘storage vessel’’ and would 

not be subject to the requirements of the 

NSPS. 

We are amending the definition of 

‘‘removed from service’’ and adding a 

definition of ‘‘returned to service’’ to 

clarify these provisions. See section 

IV.B for a detailed discussion. 

C. Routing of Reciprocating Compressor 

Rod Packing Emissions to a Process 

The 2012 final NSPS includes 

operational or ‘‘work practice’’ 

standards for reciprocating compressors 

to reduce emissions from gas vented 

from the piston rod packing as the rod 

moves during operation. The rule 

requires regular rod packing 

replacement every 26,000 hours of 

operation or, if the owner and operator 

elect, every 36 months. On October 15, 

2012, the Administrator received a 

petition for administrative 

reconsideration of the performance 

standards for reciprocating compressors 

that asserted that an alternative 

technology exists that would reduce 

emissions commensurate with or better 

than the reductions from the operational 

standard. This technology consists of 

recovering vented emissions from the 

rod packing under negative pressure 

and routing these emissions of 

otherwise vented gas to the air intake of 

a reciprocating internal combustion 

engine, or other process that would burn 

the gas as fuel to augment the normal 

fuel supply. Based on our review of the 

information submitted by the petitioner, 

we conclude that the technology has 

merit and would provide equivalent or 

better emissions reduction since the 

emissions would be captured under 

negative pressure, allowing all 

emissions to be routed to the engine. It 

is our understanding that this 

technology may not be applicable to 

every compressor installation and 

situation and, therefore, it would be 

within the operator’s discretion to 

choose whichever option is most 

appropriate for the application and 

situation at hand. 

Therefore, for the above reasons and 

as discussed in the proposed rule, we 

are revising § 60.5385(a) to include a 

third option for routing the rod packing 

emissions to a process through a closed 


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vent system that meets the requirements 

of § 60.5411(c). 

Also as proposed, we are amending 

the closed vent system requirements in 

§ 60.5411(a) and (b) to apply to 

reciprocating compressors (in addition 

to centrifugal compressor wet seal 

degassing systems, to which those 

sections already apply). Similarly, we 

are amending the continuous 

compliance requirements in § 60.5415 

and inspection and monitoring 

requirements in § 60.5416 to apply to 

reciprocating compressors. 

The EPA received comments in 

support of the addition of the third 

alternative in § 60.5385(a). However, 

commenters identified several 

inconsistencies that should be 

addressed with respect to other 

provisions as they relate to the revised 

§ 60.5385(a). The EPA agrees with the 

commenters’ rationale and is amending 

§§ 60.5410(c)(1), 60.5415(c)(4), 

60.5416(a), and 60.5420(c)(6) through 

(9) to be consistent with the intent of the 

third alternative provision in 

§ 60.5385(a)(3). Specifically, we are 

revising the initial compliance 

demonstration provisions in 

§ 60.5410(c)(1) by adding language such 

that paragraphs (c)(1) through (4) would 

not apply to sources electing to comply 

with § 60.6385(a)(3). The EPA agrees 

with commenters that these provisions 

would not apply to sources that are 

operating a closed vent systems and 

complying with § 60.5385(a)(3). We are 

revising the continuous compliance 

demonstration provisions in 

§ 60.5415(c)(4) to reflect that the source 

must comply with 60.5416(a) and (b) 

rather than § 60.5411(a) and (b). The 

EPA agrees that the provisions of 

§ 60.5416(a) and (b) are more 

appropriate for a reciprocating 

compressor operating with a closed vent 

and cover system. We are amending 

§ 60.5420(c)(6) through (9) to add 

reciprocating compressors as sources 

subject to these recordkeeping 

requirements. 

D. Equipment Leaks at Gas Processing 

Plants 

1. Small Gas Processing Plants and Gas 

Processing Plants Located on the 

Alaskan North Slope 

The equipment leaks standards in the 

1985 NSPS subpart KKK requires 

routine leak detection at natural gas 

processing plants for certain equipment, 

specifically pumps in light liquid 

service, valves in gas/vapor and light 

liquid service, and pressure relief valves 

from gas/vapor service. Subpart KKK 

provides for exemptions for pumps in 

light liquid service, valves in gas/vapor 

and light liquid service, and pressure 

relief valves in gas/vapor service from 

routine monitoring requirements at 

small natural gas processing plants (i.e., 

plants that do not have the design 

capacity to process at least 10 million 

standard cubic feet of field gas per day) 

and at natural gas processing plants 

located on the Alaskan North Slope. 

With the exception of the revision to 

lower the leak definition for valves, we 

retained the other provisions of subpart 

KKK by adopting the subpart KKK 

regulatory text, including the above 

mentioned exemptions, in subpart 

OOOO. With this complete adoption of 

subpart KKK regulatory text on the 

exemptions, we inadvertently failed to 

update the equipment list to include 

connectors, as pointed out by 

petitioners. We agree that this omission 

was an oversight and that it was not our 

intent for the 2012 NSPS to single out 

connectors at small gas processing 

plants and at gas processing plants 

located on the Alaska North Slope for 

routine leak detection while exempting 

the other equipment at these plants from 

these requirements. As a result, as 

proposed, we are amending § 60.5401(d) 

and (e) to add connectors to the list of 

equipment exempt from routine leak 

detection at these plants. 

2. Equipment Under Subpart OOOO 

Subject to Leak Detection Requirements 

Petitioners pointed out that the 

definition of ‘‘equipment’’ in § 60.5430 

of the 2012 final NSPS could be 

misinterpreted to expand the scope of 

the equipment leaks program under 

subpart OOOO to cover beyond onshore 

natural gas processing plants, which 

was the scope of subpart KKK. Except 

for lowering the leak definition for 

valves and requiring monitoring of 

connectors, subpart OOOO retains the 

other provisions of the subpart KKK by 

adopting those provisions, including the 

definition of ‘‘equipment.’’ Because 

subpart KKK pertained only to onshore 

natural gas processing plants, the phrase 

‘‘any device or system required by this 

subpart’’ refers to only devices and 

systems at onshore natural gas 

processing plants. However, since 

subpart OOOO also covers affected 

facilities not located at onshore natural 

gas processing plants, the phrase could 

be misinterpreted to apply to every 

affected facility under the entire subpart 

OOOO, including those not located at 

onshore natural gas processing plants. 

To avoid any such misinterpretation, we 

are amending the definition of 

‘‘equipment’’ in § 60.5430 to read as set 

forth in the regulatory text of this rule. 

E. Definition of ‘‘Responsible Official’’ 

The 2012 final rule requires 

certification by a responsible official of 

the truth, accuracy and completeness of 

the annual report. Petitioners pointed 

out that the definition of ‘‘responsible 

official’’ is not appropriate for the oil 

and natural gas sector due to the large 

number and wide geographic 

distribution of the small sources 

involved. Petitioners suggested that the 

EPA should develop a certification 

requirement specific to the Oil and 

Natural Gas Sector NSPS that would 

allow delegation of the authority of a 

responsible official to someone, such as 

a field or production supervisor, who 

has direct knowledge of the day-to-day 

operation of the facilities being certified, 

without requiring that such delegation 

be pre-approved by the permitting 

authority. 

We reexamined the definition of 

‘‘responsible official’’ and agree with 

petitioners that the current language in 

the NSPS, specifically the requirement 

to seek advance approval by the 

permitting authority of the delegation of 

authority to a representative if the 

facility employs 250 or fewer persons, is 

too burdensome for the oil and natural 

gas sector. Therefore, consistent with 

the proposed changes, we are also 

amending the definition to make such 

delegation effective after advance 

notification rather than after approval. 

Requirements for delegation to 

representatives responsible for one or 

more facilities that employ more than 

250 persons or have gross annual sales 

or expenditures exceeding $25 million 

(in second quarter 1980 dollars) are 

unchanged from the 2012 NSPS (i.e., 

there is no advance notification or 

approval required for such delegations). 

Petitioners also noted that the current 

definition does not adequately address 

the complex ownership arrangements of 

limited partnerships. We agree with the 

petitioners and believe limited 

partnerships should be reflected in the 

definition along with sole 

proprietorships and partnerships which 

are currently addressed. 

In the process of this evaluation, we 

also determined that the use of 

‘‘permitting authority’’ and the 

‘‘responsible official’’ are similar to 

terms used in the requirements of the 

Title V permitting program. In order to 

remove potential confusion by the 

regulated community and to clarify that 

this is a requirement of the NSPS and 

is not associated with a permitting 

program, we are changing the term 

‘‘responsible official’’ to ‘‘certifying 

official’’ and replacing the term 


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2The court’s reasoning in NRDC focuses on civil 

judicial actions. The Court noted that ‘‘EPA’s ability 

to determine whether penalties should be assessed 

for Clean Air Act violations extends only to 

administrative penalties, not to civil penalties 

imposed by a court.’’ Id. 

3Although the NRDC case does not address the 

EPA’s authority to establish an affirmative defense 

to penalties that is available in administrative 

enforcement actions, EPA had not included such an 

affirmative defense in the 2012 NSPS. As explained 

above, such an affirmative defense is not necessary. 

Moreover, assessment of penalties for violations 

caused by malfunctions in administrative 

proceedings and judicial proceedings should be 

consistent. Cf. CAA section 113(e) (requiring both 

the Administrator and the court to take specified 

criteria into account when assessing penalties). 

‘‘permitting authority’’ used in the 

definition with ‘‘Administrator.’’ 

F. Affirmative Defense 

The EPA is removing a regulatory 

affirmative defense provision from the 

rule, as proposed. For the reasons stated 

in the preamble to the proposed 

amendments and below, we are 

finalizing the removal of the affirmative 

defense provisions. In the 2012 

rulemaking, the EPA had included an 

affirmative defense to civil penalties for 

violations caused by malfunctions in an 

effort to create a system that 

incorporates some flexibility, 

recognizing that there is a tension, 

inherent in many types of air regulation, 

to ensure adequate compliance while 

simultaneously recognizing that despite 

the most diligent of efforts, emission 

standards may be violated under 

circumstances entirely beyond the 

control of the source. Although the EPA 

recognized that its case-by-case 

enforcement discretion provides 

sufficient flexibility in these 

circumstances, it included the 

affirmative defense to provide a more 

formalized approach and more 

regulatory clarity. See Weyerhaeuser Co. 

v. Costle, 590 F.2d 1011, 1057–58 (D.C. 

Cir. 1978) (holding that an informal 

case-by-case enforcement discretion 

approach is adequate); but see Marathon 

Oil Co. v. EPA, 564 F.2d 1253, 1272–73 

(9th Cir. 1977) (requiring a more 

formalized approach to consideration of 

‘‘upsets beyond the control of the permit 

holder.’’). Under the EPA’s regulatory 

affirmative defense provisions, if a 

source could demonstrate in a judicial 

or administrative proceeding that it had 

met the requirements of the affirmative 

defense in the regulation, civil penalties 

would not be assessed. Recently, the 

United States Court of Appeals for the 

District of Columbia Circuit vacated an 

affirmative defense in one of the EPA’s 

section 112 regulations. NRDC v. EPA, 

749 F.3d 1055 (D.C. Cir., 2014) (vacating 

affirmative defense provisions in section 

112 rule establishing emission standards 

for Portland cement kilns). The court 

found that the EPA lacked authority to 

establish an affirmative defense for 

private civil suits and held that under 

the CAA, the authority to determine 

civil penalty amounts in such cases lies 

exclusively with the courts, not the 

EPA. Specifically, the Court found: ‘‘As 

the language of the statute makes clear, 

the courts determine, on a case-by-case 

basis, whether civil penalties are 

‘appropriate.’ ’’ See NRDC, at 1063 

(‘‘[U]nder this statute, deciding whether 

penalties are ‘appropriate’ in a given 

private civil suit is a job for the courts, 

not EPA.’’).2 In light of NRDC, the EPA 

had proposed and is finalizing in this 

action the removal of the regulatory 

affirmative defense provisions in 

subpart OOOO. As explained above, if 

a source is unable to comply with 

emissions standards as a result of a 

malfunction, the EPA may use its caseby-case enforcement discretion to 

provide flexibility, as appropriate. 

Further, as the D.C. Circuit recognized, 

in an EPA or citizen enforcement action, 

the court has the discretion to consider 

any defense raised and determine 

whether penalties are appropriate. Cf. 

NRDC, at 1064 (arguments that violation 

were caused by unavoidable technology 

failure can be made to the courts in 

future civil cases when the issue arises). 

The same is true for the presiding officer 

in EPA administrative enforcement 

actions.3

IV. Summary of Significant Changes 

Since Proposal 

Section III summarized the 

amendments to the 2012 NSPS that the 

EPA is finalizing in this rule. This 

section discusses the key changes the 

EPA has made since proposal. These 

changes are the result of the EPA’s 

consideration of the many substantive 

and thoughtful comments submitted on 

the proposal and other information 

received since proposal. We believe that 

the changes we have made sufficiently 

address concerns expressed by 

commenters and improve the clarity of 

the rule while improving or preserving 

public health and environmental 

protection required under the CAA. 

A. Well Completions 

1. Handling of Flowback Gases and 

Liquids 

In today’s action we are finalizing 

clarifications and amendments to 

provisions for handling of gases and 

liquids during flowback at § 60.5375. 

Following publication of the 2012 final 

NSPS, we received feedback from 

petitioners that the well completion 

provisions were unclear and that 

operators were not sure of the 

requirements for handling of gas and 

liquids during well completion 

operations. Petitioners also asserted 

that, as written, compliance with the 

2012 NSPS was impossible, since the 

rule appeared to prohibit venting of gas 

at any time during the well completion. 

In our July 17, 2014, proposal, we 

clarified it was not the EPA’s intent to 

prohibit venting of flowback gases 

throughout the entire flowback period 

and we understood that there were 

periods during which gas may be 

present in the flowback but with 

insufficient volume and consistency of 

flow to enable either combustion or 

recovery of the gas after separation. We 

confirmed that the initial flowback 

(prior to recovery of gas from the liquids 

through separation) may be routed to 

storage vessels, temporary fracture tanks 

(frac tanks) or to lined pits, as long as 

separation and recovery of the gas 

occurs as soon as practicable, consistent 

with the general duty to maximize 

resource recovery and minimize releases 

to the atmosphere as required in 

§ 60.5375(a)(4). 

To clarify EPA’s intent with regard to 

handling of gas and liquid portions of 

flowback, we had proposed three 

distinct stages of the completion 

operation, with each stage having 

specific requirements for handling of 

gases and liquids. 

As proposed, the first stage would 

begin with the first flowback from the 

well following hydraulic fracturing or 

refracturing, and would be characterized 

by high volumetric flow water, with 

sand, fracturing fluids and debris from 

the formation, with very little gas being 

brought to the surface, usually in 

multiphase slug flow. Under the 

proposed amendments, the first stage 

was defined as the ‘‘initial flowback 

stage.’’ We had proposed that during 

this stage the flowback would be 

required to be routed to a ‘‘well 

completion vessel’’ that could be a frac 

tank, a lined pit or any other vessel. Our 

intention was that the flowback could 

not be directed to an unlined pit or onto 

the ground. During the initial flowback 

stage, there would be no requirement for 

controlling emissions from the tank or 

other vessel, and any gas in the 

flowback during this stage could be 

vented. We proposed that, as soon as 

sufficient gas is present in the flowback 

for a separator to operate, the flow 

would be required to be diverted to the 

separator. We explained that ‘‘for a 

separator to function enough gas must 

be flowing [in the flowback] to maintain 

a gaseous phase and one or more liquid 

phases in the separator.’’ (79 FR 41755). 

In the proposal preamble, we had 


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discussed how some operators monitor 

the gas concentration at the vessel 

receiving the flowback both for safety 

reasons and to determine that sufficient 

gas is present in the flowback for the 

separator to function. We understood 

that when the gas concentration 

approaches the lower explosive limit 

(LEL) (i.e., approaches flammability), 

these operators direct the flowback to a 

separator. We were uncertain whether 

this method could be used effectively in 

all applications and whether there were 

other techniques used by operators to 

make this determination. We solicited 

comment on the suitability of the ‘‘LEL 

method’’ when used for this purpose 

and asked for information on other 

techniques or indicators that could be 

used to determine when sufficient gas is 

present for a separator to function. 

Commenters responded that the EPA 

apparently had misunderstood earlier 

discussions regarding use of the LEL 

detector. They asserted that the detector 

is used for safety reasons and that 

although the LEL detector indicates that 

there may be potential flammability, it 

does not necessarily indicate that 

sufficient gas is present for the separator 

to function. Commenters also asserted 

that monitoring the gas concentration 

does not reflect other conditions such as 

sand and water content and well 

characteristics that have a bearing on 

the point where the separator will 

operate. We also learned that some 

operators begin to direct the flowback to 

the separator immediately upon initial 

flowback, even though it may not 

maintain a gaseous phase and one or 

more liquid phases in the separator. 

Other operators may not have an initial 

flowback stage and may go directly to 

the separation flowback stage. 

Because whether a separator can 

operate may depend on site specific 

factors other than the amount of gas 

present in the flowback, we are not 

finalizing the proposed requirement to 

commence operation of a separator as 

soon as sufficient gas is present in the 

flowback for a separator to operate. 

However, the public comments did not 

provide sufficient information regarding 

other indicators as to when a separator 

can operate. We therefore are unable to 

establish specific criteria for 

determining the point at which 

operators are required to route the 

flowback to the separator. For the 

reasons stated above, we require in the 

final amendments that flowback must be 

routed to a separator unless it is 

technically infeasible. This has always 

been our intent. Although we learned 

that technical infeasibility is not strictly 

limited to the amount of gas present, we 

believe that if this infeasibility is not 

predicated solely on the amount of gas 

present, then there must be some other 

site-specific technical issues that 

prevent a separator from functioning. 

Such technical infeasibility might 

include the separator being 

overwhelmed by the flowback, such that 

the vapor space in the separator is not 

maintained, or the liquid drain is unable 

to handle the volume of liquid flowing 

through. We further note that the 

general duty to maximize resource 

recovery and minimize releases to the 

atmosphere required in § 60.5375(a)(4) 

applies during the entire flowback 

period, including the initial flowback 

stage. 

As proposed, the second stage, 

defined as the ‘‘separation flowback 

stage,’’ begins when the flowback gases 

and liquids are routed to the separator. 

During the separation flowback stage, 

the operator would be required to route 

the recovered gas into a gas flow line or 

collection system, re-inject the 

recovered gas into the well or another 

well, use the recovered gas as an on-site 

fuel source or use the recovered gas for 

another useful purpose that a purchased 

fuel or raw material would serve. If, 

during the separation flowback stage, it 

was infeasible to route the recovered gas 

to a flow line or collection system, 

reinject the gas or use the gas as fuel or 

for other useful purpose, the recovered 

gas (i.e., ‘‘flowback emissions’’) would 

have to be combusted using a 

completion combustion device, as 

required in the 2012 NSPS at 

§ 60.5375(a)(3). No direct venting of 

recovered gas would be allowed during 

the separation flowback stage. We also 

proposed that, at any time during the 

separation flowback stage, if the gas 

present in the flowback becomes 

insufficient to maintain operation of the 

separator, the operator would revert to 

the initial flowback stage until the 

separator could again function to allow 

continuous recovery of the gas and to 

allow separation and recovery of the 

liquids. During the separation flowback 

stage, all liquids from a separator could 

be directed to one or more well 

completion vessels or storage vessels, or 

be re-injected into the well or another 

well. We are finalizing the provisions 

relative to the separation flowback stage 

as proposed, except that the operator 

can revert to the initial flowback stage 

if it is technically infeasible to maintain 

function of the separator (consistent 

with our discussion above on requiring 

the operation of a separator unless it is 

technically infeasible). We also have 

added requirements for recordkeeping 

to document each occurrence of 

reverting back to the initial flowback 

stage and the reason for the reversion. 

We had proposed that the end of the 

separation flowback stage was the point 

where separation flowback would have 

declined and stabilized enough to allow 

continuous recovery of the gas and 

where separation and recovery of any 

crude oil, condensate and produced 

water were possible. We had proposed 

that the flowback period of a well 

completion operation included only the 

initial flowback stage and the separation 

flowback stage, as flowback ended and 

ongoing production began at that point. 

Further, we had identified that point as 

the beginning of the ‘‘production stage’’ 

of the well completion. We had also 

explained at proposal that we were 

seeking to identify objective criteria for 

making a determination that flowback 

had subsided and that the well had 

reached the point where production 

could begin, marking the end of the 

separation flowback stage and the 

beginning of the production stage. We 

solicited comment on the characteristics 

of the flow or other conditions that 

could be used to establish such criteria. 

In addition, we proposed that, for 

storage vessels receiving liquids 

following the flowback period of a well 

completion, the beginning of the 

production stage would also begin the 

30-day period for determining VOC PTE 

for purposes of making a storage vessel 

affected facility determination in 

accordance with the procedure in 

§ 60.5365(e). If the criteria under 

§ 60.5365(e) were met, the operator 

would have to comply with the control 

requirements in § 60.5395(d)(1) within 

60 days after the beginning of the 

production stage. We had also proposed 

amendments to § 60.5365(e) to reflect 

that, for purposes of the well 

completion provisions, the 30-day 

period for the affected facility 

determination required in § 60.5365(e) 

would commence at the beginning of 

the production stage. During the 

production stage, any venting or flaring 

of the recovered gas would be 

prohibited. 

Several commenters took issue with 

the inclusion of the production stage as 

part of the overall well completion 

operation. The commenters contended 

that this extension confuses or 

contradicts other provisions that 

explicitly are applicable to well 

completion operations and should not 

be applicable over the lifetime of a well 

in production. The commenters asserted 

that it is critical that the rule identify 

when the flowback period ends and 

clarify that the requirements for well 

completions do not extend beyond the 

end of the flowback period. The 


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commenters explained that, because the 

production stage could conceivably 

continue for decades, it was clearly not 

a stage of well completion and was 

beyond the intended scope of § 60.5375. 

Commenters also gave examples of the 

ramifications of this concept. They 

asserted that prohibition of venting and 

flaring for the lifetime of the well would 

preclude planned maintenance 

workovers, flaring of amine system 

overhead gas and venting of carbon 

dioxide. 

We agree with the commenters that 

the production stage should not be a 

stage of well completion and 

understand that compliance with the 

well completion provisions (which were 

intended only for the flowback period) 

would be impossible were these 

provisions applicable throughout the 

life of the well. As a result, we are 

finalizing requirements for well 

completions that identify two stages of 

well completion, the initial flowback 

stage and the separation flowback stage. 

As discussed above, we had proposed 

that the point where separation 

flowback would have declined and 

stabilized enough to allow continuous 

recovery of the gas and where 

separation and recovery of any crude 

oil, condensate and produced water 

were possible would be the end of the 

separation flowback stage and the 

beginning of the production stage. We 

solicited information that could identify 

criteria for defining this point. 

Commenters explained that removal of 

flowback equipment and absence of 

well completion personnel were two 

indicators that flowback had subsided 

and the well had cleaned up sufficiently 

to allow production to begin. 

In addition to the information 

provided by commenters, it is our 

observation that the permanent 

disconnection of the temporary 

equipment used during flowback can be 

an indicator of flowback having ended. 

For example, during flowback, skidmounted choke manifolds are used to 

limit flowback and assist in directing 

the flow. Temporary lines laid on the 

ground from the wellhead to the choke 

manifold and to the flowback separators 

and frac tanks are connected with 

‘‘hammer unions’’ which are pipe 

unions that are designed for ease of 

making temporary connections and are 

characterized by ‘‘ears’’ that allow the 

joint to be made up quickly by striking 

with a hammer. After flowback has 

subsided and the well has cleaned up 

sufficiently, the well is temporarily shut 

in to disconnect the temporary flowback 

equipment. We believe that when the 

operator permanently disconnects choke 

manifolds, temporary separators, sand 

traps and other equipment connected 

with temporary lines and hammer 

unions, it is a reliable indicator that 

flowback has ended and the well is 

ready for production. At that point, we 

believe that operators will remove these 

temporary equipment used during 

flowback to avoid incurring unnecessary 

charges for additional days the 

equipment remains onsite. The well 

could start production immediately or it 

could remain shut in until permanent 

equipment is installed some time later. 

In light of the above considerations, 

we are amending the NSPS such that the 

end of the separation flowback stage is 

defined as the startup of production, or 

when the well is shut in and the 

temporary flowback equipment has been 

permanently disconnected from the 

well. We are also finalizing amendments 

that identify the startup of production, 

rather than the beginning of the 

production stage, as the beginning of the 

30-day period for determining storage 

vessel PTE according to the 

requirements of § 60.5365(e). 

As discussed in section V.A, we had 

received comment that some operators 

route gas and liquids from the well site 

to other facilities for collection and 

suggested we specify ‘‘collection 

system’’ as one of the options for 

disposition of flowback liquids and 

recovered gas. We agree with the 

commenter and have included 

‘‘collection system’’ in the provisions 

for gas and liquids handling during well 

completions. To provide clarity, we also 

have added a definition in § 60.5430 for 

‘‘collection system’’ which is presented 

in section V.A. 

We are finalizing the liquids handling 

requirements during the flowback 

period as proposed, with the slight 

revision to the definition of the 

separation flowback stage as described 

above. During the flowback period, 

which includes the initial flowback 

stage and the separation flowback stage, 

the liquid portion of the flowback must 

be directed to storage vessels, well 

completion vessels, injected into the 

well or another well or routed to a 

collection system. 

In the proposed rule, we had provided 

that the 30-day period for estimating the 

VOC PTE of a storage vessel receiving 

recovered liquids would begin at the 

beginning of the production stage. With 

the revision to the stages of completion 

discussed above, ‘‘startup of 

production’’ would replace ‘‘beginning 

of the production stage.’’ Because we 

believe it is important to achieve control 

of storage vessel affected facilities as 

soon as practicable, we believe it is 

important to begin the 30-day period for 

estimating storage vessel VOC PTE as 

soon as this estimation can be achieved 

and will provide a representative 

estimate of the storage vessel’s PTE 

during production. As a result, we 

believe it is necessary to begin the 

estimation period after flowback ends, 

immediately after the end of the 

separation flowback stage, since the 

flowback period is not representative of 

liquids flow and composition during 

production. Estimation during the 

flowback period could result in PTE 

estimates being either abnormally low 

or abnormally high, since very early in 

flowback the liquid is predominantly 

water flowing at a high rate, while 

immediately after flowback, the volume 

has subsided but VOC content of the 

liquid may be much higher. Tank 

emission estimation methods generally 

require information on both the 

composition of the liquid entering a 

storage vessel (generally obtained 

through analysis of a pressurized 

sample of the liquid obtained from the 

separator) and the volumetric rate of the 

liquid (often in barrels per day). Because 

the analytical samples are taken from 

the separator and the volume is 

calculated by recording the liquid 

collection from the receiving vessel, it is 

not necessary to have a permanent 

storage vessel installed in order to 

perform this estimation, and the 

sampling and volume tracking can begin 

at any time after the end of flowback, 

while the liquids are being collected in 

a well completion vessel or a storage 

vessel. Based on these considerations, 

we are finalizing the requirement that 

liquid during flowback may be routed to 

a well completion vessel or storage 

vessel. Also, based on these 

considerations, we are clarifying that 

recovered liquids may continue to be 

routed to a well completion vessel or a 

storage vessel after the startup of 

production, but that a well completion 

vessel to which recovered liquids are 

routed for a period in excess of 60 days 

after startup of production is considered 

a storage vessel subject, depending on 

its PTE, to control under § 60.5395, as 

with any other storage vessel affected 

facility. In addition, we are amending 

the definitions of ‘‘storage vessel’’ and 

‘‘well completion vessel’’ to be 

consistent with this requirement. We are 

amending § 60.5395(d)(1)(i) to reflect 

that, for purposes of the well 

completion provisions, control would 

be required no later than 60 days from 

startup of production. Consistent with 

these changes we are amending 

§ 60.5395(d)(1)(i) to read as set forth in 

the regulatory text of this rule. 

We note that we have received 

requests for clarification of the meaning 


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of ‘‘maximum average daily 

throughput’’ as used in the VOC PTE 

determination language in § 60.5365(e). 

The 2013 final rule that promulgated 

storage vessel implementation 

amendments in which this term first 

appeared in the NSPS provided limited 

guidance on how operators should 

determine ‘‘maximum average daily 

throughput,’’ and no definition of this 

term was included in the July 2014 

proposed rule. The discussion above 

explains that PTE determination 

methods generally are based on 

modeling performed using results of 

analysis of pressurized samples from the 

separator combined with liquid 

throughput over some period that 

corresponds with the separator sample. 

We believe that the ‘‘maximum average 

daily throughput’’ is determined by the 

earliest calculation of daily average 

throughput during the 30-day 

evaluation period employing generally 

accepted methods. Based on the 

performance of wells over time, this 

initial calculation would represent the 

maximum average daily throughput that 

could be expected for the storage vessel. 

To provide more clarity in the rule, we 

have added a definition of ‘‘maximum 

average daily throughput’’ in § 60.5430. 

We are aware that issues remain 

concerning this term and continue to 

consider how to resolve them. 

B. Storage Vessels 

1. Storage Vessels Removed From 

Service and PTE Determination 

As proposed, we are amending 

§ 60.5395(f) and § 60.5420(b)(6) to 

require that the dates that storage vessel 

affected facilities are removed from 

service and returned to service be 

included when reporting those actions. 

For the reasons discussed below, we 

are also amending the NSPS to clarify 

that storage vessel affected facilities 

removed from service (which is defined 

as when they are physically 

disconnected from their source of 

liquids for reasons other than 

maintenance and are emptied and 

degassed) cease to be storage vessel 

affected facilities under the NSPS. We 

received comment, with which we 

agree, that storage vessel emissions are 

a function of the specific use of the 

vessel as installed—determined by 

factors such as the type of liquid it is 

used to contain, the liquid throughput 

of the vessel, and the pressure drop of 

the liquid entering the vessel causing 

flash emissions. As a result, removing a 

storage vessel from service in one use 

and moving it to a new use could 

drastically change its emissions 

characteristics. To be classified a 

‘‘storage vessel’’ as defined in § 60.5430, 

a tank or other vessel must be used to 

contain crude oil, condensate, 

intermediate hydrocarbon liquids or 

produced water. Should the tank or 

other vessel cease being used to contain 

any of these liquids, it would no longer 

meet the definition of ‘‘storage vessel.’’ 

In light of these considerations, we 

believe that a storage vessel affected 

facility that has been physically isolated 

and disconnected from the process for a 

purpose other than maintenance, has 

been completely emptied and degassed 

and is no longer used to contain crude 

oil, condensate, produced water or 

intermediate hydrocarbon liquids 

should not be subject to requirements 

under the NSPS for the period of time 

it is removed from service. 

A vessel, whether it is in service for 

the first time or after being removed 

from service, falls into one of three 

categories: (1) It is installed to replace 

a storage vessel affected facility or is 

connected in parallel with a storage 

vessel affected facility, where liquids to 

be contained and VOC PTE for the 

application are already known; (2) the 

vessel does not replace a storage vessel 

affected facility but is being returned to 

service to contain crude oil, condensate, 

intermediate hydrocarbon liquids or 

produced water with unknown PTE; or 

(3) the vessel is being used in an 

application other than to contain crude 

oil, condensate, intermediate 

hydrocarbon liquids or produced water. 

A vessel falling under the first 

category, that is replacing or is being 

connected in parallel with a vessel that 

has already been determined to be a 

‘‘storage vessel affected facility’’ based 

on a known PTE, in effect takes the 

place of the affected facility being 

replaced or with which it is being 

connected in parallel and, as such, 

should be immediately subject to the 

same requirements as the storage vessel 

affected facility being replaced. There is 

no need for the 30-day period after 

startup allowed under § 60.5365(e) for 

determining its VOC PTE and the 60- 

day period after startup allowed under 

§ 60.5395(c) for applying control. In 

short, a vessel in this category should be 

subject immediately upon startup to the 

same requirements as the storage vessel 

affected facility it is replacing. For 

example, a vessel that is replacing a 

storage vessel affected facility subject to 

the 95.0 percent control requirement in 

§ 60.5395(d)(1) would be subject to 

§ 60.5395(d)(1), whereas a vessel that is 

replacing a storage vessel affected 

facility subject to the 4 tpy alternative 

uncontrolled emission standard in 

§ 60.5395(d)(2) would be subject to 

§ 60.5395(d)(2). 

For vessels in the second category, 

i.e., the vessel does not replace a storage 

vessel affected facility but is being 

returned to service to contain crude oil, 

condensate, intermediate hydrocarbon 

liquids or produced water with 

unknown PTE, the 30-day period for 

determining the VOC PTE and the 30- 

day period for installation of control if 

the PTE is 6 tpy or above would apply. 

For vessels in the third category, i.e., 

the vessel is being used in an 

application other than to contain crude 

oil, condensate, intermediate 

hydrocarbon liquids or produced water, 

the vessel continues to not meet the 

definition of ‘‘storage vessel’’ for this 

rule and has no requirements while in 

this service. 

Although we believe it is an unlikely 

occurrence, we note that, when two or 

more storage vessels receive liquids in 

parallel, the total throughput is shared 

between or among the parallel vessels 

and, in turn, this causes the PTE of each 

vessel to be a fraction of the total PTE. 

In these cases, the EPA would consider 

the parallel storage vessels equivalent to 

a single vessel with PTE equal to the 

sum of the PTE of the individual 

vessels. As a result, the parallel storage 

vessels would be considered storage 

vessel affected facilities and subject to 

control if the total PTE was at least 6 

tpy. If one of the parallel storage vessels 

has already been determined to be an 

affected facility and is subject to storage 

vessel requirements, no PTE calculation 

is necessary for the other parallel 

storage vessels because the PTE is 

already known to be at least 6 tpy. In 

that event, all storage vessels receiving 

liquids in parallel to the storage vessel 

affected facility are subject to the same 

requirements immediately upon startup. 

As a result of the above considerations, 

we are amending the current definition 

of ‘‘removed from service’’ and adding 

a definition of ‘‘returned to service’’ to 

clarify these provisions. The definitions 

read as set forth in the regulatory text of 

this rule. 

We are also amending § 60.5395(f) to 

include requirements for storage vessels 

removed from service and returned to 

read as set forth in the regulatory text of 

this rule. 

C. Definition of ‘‘Responsible Official’’ 

In our proposed action, the EPA 

proposed to amend the definition of 

‘‘responsible official’’ to address several 

concerns identified by petitioners as 

discussed above in section III.E. In our 

evaluation of comments received from 

regulatory authorities and industry, we 

determined that the terminology used 

for the definition of ‘‘responsible 

official’’ too closely mirrored 


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terminology used in the Title V 

permitting program. As the 

requirements of subpart OOOO are 

separate and distinct from those of any 

permitting program, we found that the 

use of those terms was inappropriate for 

subpart OOOO and could potentially 

cause confusion of regulated entities. 

Therefore, in addition to the proposed 

change to the definition to reduce the 

burden of the advance delegation 

requirements on the oil and gas 

industry, we are changing the term 

‘‘responsible official’’ to ‘‘certifying 

official’’ and changing the term 

‘‘permitting authority’’ used in the 

definition to ‘‘Administrator.’’ 

V. Summary of Significant Comments 

and Responses 

This section summarizes the 

significant comments on our proposed 

amendments and our response thereto. 

A. Well Completions 

1. Handling of Gases and Liquids 

Comment: One commenter concurs 

that many wells undergo the three 

stages of well completion as defined in 

the preamble to the proposed rule, but 

not all wells. The commenter points to 

the Fayetteville Shale where the 

flowback from many of their wells are 

routed directly to a separator with gas 

recovered into gathering lines and 

produced water sent to frac tanks and 

then to lined earthen retention ponds. 

The commenter asserts that these wells 

do not undergo the initial flowback 

stage nor the separation flowback stage 

and instead go directly into production 

stage as defined in the proposed rule. 

Response: The EPA acknowledges 

that there are differences in reservoir 

characteristics and the resultant 

variations in composition of the 

flowback between shale plays and even 

within a given shale play. These 

differences affect how the well 

completion process is conducted. As we 

discussed in section IV.A, we are aware 

that some operators are able to route the 

flowback directly to a separator, 

essentially bypassing the initial 

flowback stage. We agree with the 

commenter that this is possible in some 

cases; however, that may not be true for 

all situations. The final rule requires 

operators to direct the flow to the 

separator unless it is technically 

infeasible for the separator to function 

(which we explain in further detail in 

section IV.A) and minimize releases to 

the atmosphere as required by 

§ 60.5375(a)(4). We disagree with the 

commenter that their operation bypasses 

both stages of flowback, if the 

operations the commenter described 

used a temporary separator or other 

temporary flowback equipment. If a 

temporary separator or other temporary 

flowback equipment were used, then the 

operation would bypass the initial 

flowback stage but enter the separation 

flowback stage and would be subject to 

the requirements of § 60.5375(a)(1)(ii). If 

such temporary flowback equipment is 

not used, then the completion operation 

is indeed considered to enter directly 

into production at the beginning of 

flowback, which in this case would be 

considered ‘‘startup of production,’’ that 

begins the 30-day period for 

determining VOC PTE for purposes of 

making a storage vessel affected facility 

determination in accordance with the 

procedure in § 60.5365(e). However, 

should the well completions described 

by the commenter involve the use of 

temporary flowback equipment, then 

the onset of flowback would begin the 

separation flowback stage, which would 

continue until the well was shut in and 

the temporary flowback equipment was 

removed. There would be no initial 

flowback stage in either case described 

above. 

Comment: One commenter supports 

the EPA’s proposed definition of initial 

flowback stage because they have 

received information in the subpart 

OOOO annual reports that control was 

not possible or necessary because there 

was insufficient gas to route to a control 

device. Further, to ensure that emissions 

are not unnecessarily vented, the 

commenter supports the EPA’s 

establishment of clear criteria for 

determining when there is sufficient gas 

to operate the separator, as well as the 

delineation between the initial and 

separation flowback stages. The 

commenter is concerned that without 

additional, clear criteria, operators will 

unnecessarily vent rather than control 

emissions. The commenter, therefore, 

requests that the EPA clarify the criteria 

for reversion to initial flowback stage 

from separation flowback stage when 

the recoverable gas present in the 

flowback becomes insufficient to 

maintain operation of the separator. 

Response: As stated above, under the 

final rule, the second stage, defined as 

the ‘‘separation flowback stage,’’ begins 

when the flowback is routed to the 

separator, which is required unless it is 

technically infeasible. The issues raised 

by the commenter are discussed in 

depth in sections III.A and IV.A. 

Comment: One commenter expressed 

concern with the proposed definition of 

the separation flowback stage which 

states that ‘‘the separation flowback 

stage ends when the production stage 

begins or when the well is shut in, 

whichever is first.’’ The commenter 

contends that the well shut in provision 

should be removed. The commenter 

states that in a typical well completion 

operation, prior to commencing 

production, the well may be shut in to 

remove the flowback equipment and 

install production equipment. In some 

instances, the well may be temporarily 

shut in for other purposes such as 

making adjustments or performing 

unexpected maintenance on the 

flowback equipment. Following these 

activities, the well is re-opened and 

separation flowback may resume. 

According to the commenter, the 

proposed rule would consider the well 

in the ‘‘production stage’’ when the well 

is shut in regardless of whether it 

actually enters into production or 

returns to the flowback process after 

temporary shut in. The commenter 

believes it is more accurate for the rule 

to state that the end of the separation 

flowback stage occurs when production 

(not the ‘‘production stage’’) begins. The 

commenter provides suggested revisions 

to the definition for separation flowback 

stage. 

Response: The EPA agrees with the 

commenter that a well may be shut in 

for various reasons and that shut in 

alone does not necessarily depict the 

point of transition into production. As 

described in detail in section IV.A, there 

are other conditions such as having the 

temporary flowback equipment 

disconnected that indicate the end of 

flowback that should be taken into 

account in combination with well shut 

in. Further, although this commenter 

did not raise this issue, as discussed in 

an earlier response, sometimes operators 

can startup production without shutting 

in the well by running the temporary 

flowback equipment in parallel with the 

permanent flow line such that they can 

open the valve from the wellhead to the 

flow line and close the valve from the 

wellhead to the temporary flowback 

equipment, and isolate the temporary 

equipment for removal. As a result, the 

well is not shut in, but the temporary 

flowback equipment would be removed. 

In such cases, production had started 

without well shut in. In light of the 

above, in the final rule, we have defined 

the ‘‘separation flowback stage’’ to 

include two sets of criteria which 

identify the end of the separation 

flowback stage. The new definition 

indicates that the end of the separation 

flowback stage ends at the startup of 

production, or when the well is shut in 

and permanently disconnected from the 

flowback equipment. Therefore, a shut 

in condition of the well alone will not 

be considered the end of the separation 

flowback stage so long as flowback 


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equipment is still connected and 

production has not begun. 

Comment: One commenter points out 

that there is a point at which gas can be 

separated from fluids, but the gas is not 

yet of salable quality. The commenter 

recommends that the EPA allow flaring 

of non-sales quality gas because it 

cannot be recovered and sold, and 

recommends that § 60.5375 be amended 

to refer to ‘‘salable quality’’ gas from the 

gas outlet of the separator and similar 

changes to the definitions of 

‘‘production stage,’’ ‘‘recovered gas’’ and 

‘‘reduced emissions completion’’ in 

§ 60.5430. 

Another commenter states that 

§ 60.5375(a)(2) specifies only one of the 

suitable options for salable quality 

recovered gas. The commenter suggests 

that this section be modified to say ‘‘all 

salable quality recovered gas must be 

routed to a gas flow line or collection 

system, re-injected into the well or 

another well, used as an onsite fuel 

source, or used for another useful 

purpose that a purchased fuel or raw 

material would serve.’’ Alternatively, 

this paragraph could be deleted in that 

it is redundant given § 60.5375(a)(1)(ii). 

Response: The EPA agrees with the 

commenter’s assertion that some gas 

recovered during the separation 

flowback stage may not be of salable 

quality. The NSPS defines ‘‘salable 

quality gas’’ as ‘‘natural gas that meets 

the flow line or collection system 

operator specifications, regardless of 

whether such gas is sold.’’ It is our 

intent to prohibit the direct venting of 

any gas during the separation flowback 

stage. However, because we are aware 

that not all recovered gas is of salable 

quality, the final rule requires an 

operator to route all salable quality 

recovered gas from the separator to a gas 

flow line or collection system, re-inject 

the recovered gas into the well or 

another well, use the recovered gas as 

an on-site fuel source or use the 

recovered gas for another useful purpose 

that a purchased fuel or raw material 

would serve. However, if, during the 

separation flowback stage, it is 

infeasible to route the recovered gas to 

a flow line or collection system, reinject 

the gas or use the gas as fuel or for other 

useful purpose, the recovered gas must 

be combusted. No direct venting of 

recovered gas is allowed during the 

separation flowback stage. 

We believe these options effectively 

address all gas conditions (salable or 

non-salable) encountered during the 

separation flowback stage. For example, 

should the gas not meet minimum 

quality standards for entering the 

gathering system, we believe that would 

render collection ‘‘infeasible’’ until such 

time that the quality of the gas had 

improved and was acceptable. As a 

result, the non-salable quality gas would 

be combusted. 

Comment: Several commenters point 

out that § 60.5375(a)(1)(ii) allows 

limited options on how liquids from the 

separator must be handled. According to 

the commenters, condensate is not 

always sent to a storage vessel at the 

well site during production, but rather 

is routed to a condensate or mixed well 

stream line and piped to another 

location. Sometimes the condensate is 

piped to a central processing facility or 

tank battery, and sometimes it is piped 

to a condensate stabilization facility 

where the condensate is heated and 

stabilized at a lower vapor pressure 

prior to going to a condensate tank so 

as to avoid flashing in the tank. One 

commenter states that in the Eagle Ford 

shale play they often elect to install 

blowcase units to maximize condensate 

recovery and to enable the direct routing 

of recovered liquids from the separator 

to a condensate collection system. This 

design and practice would, according to 

the commenter, eliminate or reduce the 

need for atmospheric storage vessels. 

According to the commenters, the 

proposed rule’s requirement that 

recovered liquids must be routed to a 

storage vessel could be misinterpreted 

by regulatory agencies to not allow for 

companies to pipe the condensate to 

another location. For the separation 

flowback stage, paragraph 

§ 60.5375(a)(1)(ii) should be revised to 

clarify that liquids may be routed to a 

collection system. 

Response: It is the EPA’s intention to 

allow any innovative management 

practice for these materials that 

encourages resource conservation, gas 

recovery and emissions reductions. We 

agree that routing liquids to centralized 

collection systems mentioned by the 

commenter is an innovative approach 

that results in reduced emissions, since 

the liquids are conveyed to the central 

facility through closed pipes, reducing 

emissions. The commenter mentioned 

production, and also cited the 

provisions for the separation flowback 

stage at § 60.5375(a)(1)(ii). We believe 

that collection systems should be 

allowed as one of the options for 

handling liquids during flowback and 

during production. In light of the 

comments received and our belief that 

centralized collection systems are 

protective of the environment, the final 

rule requires that during the separation 

flowback stage, all liquids from the 

separator must be directed to one or 

more well completion vessels or storage 

vessels, routed to a collection system or 

be re-injected into the well or another 

well. To further clarify this requirement, 

we have added a definition for 

‘‘collection system’’ in § 60.5375 as set 

forth in the regulatory text of this rule. 

Comment: One commenter expresses 

concern that allowing liquids from the 

separator to be routed to a well 

completion vessel, which as defined in 

the proposed rule includes lined 

earthen pits and as described in the 

proposal preamble includes open top 

frac tanks, may allow the release of 

emissions from recovered gas and other 

hydrocarbons. The commenter requests 

that the EPA clarify that the use of ‘‘well 

completion vessels,’’ like the use of 

‘‘storage vessels,’’ during the separation 

flowback stage, will not result in 

emissions from recovered gas or other 

hydrocarbons. 

Response: Because of the high 

volumes of liquids encountered during 

flowback, both in the initial flowback 

stage and in the separation flowback 

stage, we believe it is appropriate to 

route flowback liquids to a well 

completion vessel. Flowback consists 

largely of water both from the fracturing 

operation and water produced from the 

formation. In addition, such high 

volumes potentially could cause damage 

to sealed and controlled storage vessels 

which operate essentially at 

atmospheric pressure and are not 

designed to handle elevated pressures 

that could be caused by surges. 

Although we understand that there may 

be some emissions from these vessels, 

our intent in the well completion 

requirements of the NSPS is to require 

practices that will minimize releases to 

the atmosphere and maximize resource 

recovery, such as separation and 

collection of gas from the flowback 

unless it is technically infeasible for the 

separator to function and requiring gas 

that cannot be routed to the flow line to 

be combusted. 

Comment: One commenter contends 

that limiting exceptions to the REC 

requirement is important, given that 

flaring of completion emissions 

represents a waste of natural resources 

and results in emissions of nitrogen 

oxides (NOX) and carbon dioxide (CO2) 

that offset the benefits of methane and 

VOC reduction. In this regard, the 

commenter is concerned that the 

proposed amendments continue to 

allow for excessive combustion of 

completion emissions, instead of the use 

of REC, when the producer deems it 

‘‘infeasible’’ to capture completion 

emissions for sale or beneficial use. 

The commenter believes that the 

proposed amendments would not only 

preserve this vague exception, but also 

problematically include preamble text 

suggesting that a producer can invoke 


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the exception in circumstances that are 

contrary to the original intent of subpart 

OOOO. The commenter contends that in 

the preamble to the final rule 

promulgating subpart OOOO, the EPA 

explained its ‘‘understanding’’ that 

producers ordinarily ‘‘plan their 

operations . . . to ensure their product 

has a viable path to market before 

completing a well,’’ and that 

combustion in lieu of a REC would only 

be necessary in ‘‘isolated cases.’’ 

However, the preamble to the current 

proposed rule indicates that a REC 

could be deemed ‘‘infeasible’’ merely 

because ‘‘there [is] no flow line or other 

infrastructure available at the site for 

collection of the gas.’’ This preamble 

text implies that the ‘‘infeasibility’’ 

exception could be used for logistical 

reasons or for the convenience of the 

producer, rather than in ‘‘isolated’’ cases 

where inherent characteristics of the 

completion prevent the capture of 

emissions for sale or beneficial use. 

Accordingly, the commenter urges the 

EPA to either eliminate or expressly 

limit the scope of the infeasibility 

exception in the final rule to ensure that 

it is consistent with the original 

structure and intent of subpart OOOO 

and is not used inappropriately. 

Specifically, the commenter 

recommends that the EPA include 

regulatory text clarifying that collection 

of completion emissions in the 

separation flowback stage is required 

unless it is technically infeasible due to 

inherent characteristics of the flowback 

or unexpected conditions, not for 

logistical reasons that are within the 

control of the operator. The commenter 

believes this clarification would provide 

operators the flexibility to use 

combustion instead of REC when 

necessary, while ensuring that 

combustion is an option of last resort. 

Response: We agree with the 

commenter that the intent of the rule is 

to minimize completion emissions 

during the separation flowback stage 

and to maximize recovery of the gas to 

the flow line. The final rule requires the 

operator to route the recovered salable 

gas to a gas flow line or collection 

system, re-inject the recovered gas into 

the well or another well, use the 

recovered gas as an on-site fuel source 

or use the recovered gas for another 

useful purpose that a purchased fuel or 

raw material would serve. If, during the 

separation flowback stage, it is 

infeasible to route the recovered gas to 

a flow line or collection system, reinject 

the gas or use the gas as fuel or for other 

useful purpose, the recovered gas must 

be combusted. No direct venting of 

recovered gas is allowed during the 

separation flowback stage. 

While we understand the commenters 

concern about using the infeasibility 

provision to combust recovered gas 

when a flow line is not available, we 

point out that these are gas wells drilled 

for the production of gas; therefore the 

operator will have planned to be able to 

produce the well commercially by 

having the infrastructure in place and 

will generally avoid completing wells 

when it is known that the infrastructure 

to collect the gas and route it to market 

will not yet be available. However, there 

will be cases, though we believe to be 

rare, in which the operator, for reasons 

not within his or her control, is unable 

to acquire access to a flow line in time 

for the well completion due to 

unforeseen circumstances. 

Comment: Several commenters took 

issue with the inclusion of the 

production stage as part of the overall 

well completion operation. The 

commenters contend that inclusion 

confuses or contradicts other provisions 

that explicitly are applicable to well 

completion operations and not to a well 

in production. The commenter believes 

it is critical that the rule identify when 

the flowback period ends and clarify 

that the requirements for well 

completions do not extend beyond the 

end of the flowback period. 

For the commenter, the problems 

arise in the provisions of 

§ 60.5375(a)(1)(iii) and in the definition 

of ‘‘production stage.’’ Paragraph 

60.5375(a)(1)(iii) specifies requirements 

for the production stage, yet this 

paragraph is a subparagraph of 

§ 60.5375(a), which is expressly 

applicable to well completion 

operations. Further, the commenter 

states that, in the proposed rule, while 

the beginning of the production stage 

marks the end of well completion 

operations, § 60.5365(e) indicates that 

the beginning of the production stage 

also marks the commencement of the 

period for determining storage vessel 

applicability. The commenter believes 

that there should be no requirements 

applicable to production following the 

end of flowback in this paragraph. One 

of the commenters believes that the 

EPA’s intent of including the 

production stage is to ensure a storage 

vessel emissions evaluation occurs 

immediately upon the start of 

production. However, the commenter 

points out that storage vessel 

requirements in § 60.5365(e) already 

dictate that an emissions evaluation 

must begin at startup. Any such 

requirements for storage vessels should 

be specified in applicable portions of 

§ 60.5365 and § 60.5395. 

The commenter believes the 

definition of production stage requires 

some editing in order to be consistent 

with the intent that requirements for 

well completion operations end when 

production begins. The commenters 

make several recommendations to the 

change of the terms ‘‘production stage’’, 

and editing of other provisions to 

minimize any misinterpretation of the 

term ‘‘production’’ in well completion 

operations requirements. The 

commenter also recommends that the 

last sentence of § 60.5375(a)(1)(ii) be 

deleted and replaced with language 

indicating to the effect that ‘‘the 

separation flowback stage ends and 

production begins when flow resumes 

after flowback equipment is removed 

from the well and flowback crews are 

released.’’ See the Response to 

Comments Document for a full 

discussion of these comments. 

Response: The EPA agrees with the 

arguments presented by the commenter 

regarding confusion and opportunity for 

misinterpretation of well completion 

requirements to be applicable during 

production. It is not the intent that rule 

provisions for well completions and the 

flowback period be applicable to the 

well during production over the lifetime 

of the well. As such, the final 

amendments do not include the term 

‘‘production stage’’ or its definition. All 

references to ‘‘production stage’’ in the 

proposed amendments have been 

removed or changed to ‘‘startup of 

production’’ in the final amendments. 

Accordingly, the well completion 

requirements do not carry over beyond 

the end of the flowback period. 

Comment: One commenter notes that 

they have many wells that go straight to 

the production stage, as defined in the 

proposed rule. The gas is recovered to 

a gathering line, but the liquids 

(produced water) are routed to a 

portable frac tank and then to either 

additional frac tanks or a lined earthen 

retention pond for storage. In some 

cases, the commenter states that the 

produced water is routed to the frac 

tanks because state regulations do not 

allow produced water to be routed 

directly to lined earthen retention 

ponds. The commenter also contends 

that routing the produced water to the 

frac tank also provides for better flow 

measurement and better control of flow 

into the retention pond, as well as 

allowing for additional sediment 

deposition and recovery within the frac 

tank. The produced water is then 

reused/recycled in subsequent well 

completions, reducing fresh water 

demands. 

The commenter is concerned that if 

the proposed rule is finalized, they 

would be prohibited from using frac 

tanks and lined earthen retention ponds 


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(well completion vessels) to recover and 

reuse produced water upon entering the 

production stage for those wells that go 

directly to the production stage (for 

these wells, upon commencing 

flowback). The commenter does not 

believe it was the EPA’s intent to 

adversely impact water reuse and 

recycling practices and requests that in 

the final rule, ‘‘well completion vessel’’ 

should be included in the standards for 

the production stage. 

The commenter understands that the 

EPA may have concerns over allowing 

the use of well completion vessels 

during the production stage due to the 

potential for VOC emissions. However, 

according to the commenter in the shale 

gas plays where the gas composition 

contains either no or negligible amounts 

of hydrocarbons, the resultant VOC 

emissions would be negligible as well. 

The commenter suggests that the EPA 

consider exempting shale gas flowback 

liquids from being required to be routed 

to a storage vessel on the basis of 

hydrocarbon gas composition and 

negligible VOC emissions. 

Response: As stated previously, the 

final amendments do not include the 

term ‘‘production stage’’ or the 

associated well completions 

requirements that were in the proposed 

amendments. The final rule, as 

amended, states that flowback period 

ends when either the well is shut in and 

well completion equipment is removed 

from the well, or that production has 

started. With respect to the types of 

wells identified by the commenter, 

these wells would be subject to the same 

requirements as other wells. However, 

we disagree with the commenter that 

these wells enter directly into 

production, since apparently there is 

water from the flowback that is 

separated from the gas and routed to 

frac tanks. As a result, such wells may 

not go through the initial flowback stage 

but would enter the separation flowback 

stage. We remind the commenter that, 

even if there is no initial flowback stage 

or separation flowback stage as defined 

by the rule, then the requirements of 

§ 60.5375(a)(2) through (4) still apply. It 

should be noted that there is nothing in 

the rule that prohibits the use of the 

types of structures which would be well 

completion vessels during the initial 

and separation flowback stage for the 

life of the well; however, once the well 

has begun production, the vessels then 

become ‘‘storage vessels’’ under the rule 

if they continue receiving liquids from 

the well for a period exceeding 60 days 

from startup of production. 

Accordingly, they would be subject to 

the same VOC PTE determination and, 

if PTE was at least 6 tpy, would be 

subject to the cover, closed vent system 

and control requirements. 

2. Definition of Low Pressure Gas Well 

In the 2012 final rule, we had 

included a definition of ‘‘low pressure 

gas well.’’ This was added as a logical 

outgrowth of the public comments 

received on the August 23, 2011 

proposed rule (76 FR 52738) that 

asserted that due to the reservoir 

pressure, well depth and gathering line 

pressure, it was infeasible to perform an 

REC for some wells. We developed a 

definition based on well parameters 

taking into account fluid mechanics and 

other engineering principles. 

Development of the definition was 

described in detail in the Technical 

Support Document for the final rule 

which is in the docket. Following 

publication of the final rule, we 

received petitions that asserted that we 

had not provided the public an 

opportunity to comment on the 

definition. We proposed the definition 

in our July 2014 proposed amendments 

to provide the public an opportunity to 

comment. We also presented and 

solicited comment on an alternative 

definition provided by the petitioners. 

Comment: Two commenters 

appreciate the EPA’s willingness to 

propose for further comment the 

definition of ‘‘low pressure gas well’’ 

found at § 60.5430. The EPA noted that 

an alternative definition that was 

submitted for its consideration by 

industry petitioners was ‘‘a well where 

the field pressure is less than 0.433 

times the vertical depth of the deepest 

target reservoir and the flowback period 

will be less than 3 days in duration.’’ 

The commenters support the alternative 

definition, although one of the 

commenters suggests that the word 

‘‘initial’’ should be placed before the 

word ‘‘flowback’’ so that it is clear that 

the three-day period in the definition 

refers to the initial flowback period, and 

does not include the separation 

flowback. This commenter adds that 

this definition is one that is consistent 

with the manner in which low pressure 

wells are generally described in the 

Appalachian Basin, is easier to use and 

is not as susceptible to 

misunderstanding. 

Response: In the proposed rule we 

solicited comment on the alternative 

definition suggested by the petitioners 

and on specific concerns or questions 

we have with respect to the alternative 

definition. We received no comments 

that provided any data or other 

information that would lead us to 

conclude that the alternative definition 

is sufficient to predict whether an REC 

would be infeasible for wells meeting 

the alternative definition. 

As explained in the proposal, we 

agree with the petitioners that this 

alternative definition is straightforward 

and easy to use. However, we are 

concerned that it may be too simplistic 

and may not adequately account for the 

parameters that must be taken into 

account when determining whether a 

REC would be feasible for a given 

hydraulically fractured gas well. 

Further, we question how an operator 

would know before flowback begins that 

the flowback period would be less than 

3 days in duration. 

We believe that, to determine whether 

the flowback gas has sufficient pressure 

to flow into a flow line, it is necessary 

to account for reservoir pressure, well 

depth and flow line pressure. In 

addition, it is important for any such 

determination to take into account 

pressure losses in the surface equipment 

used to perform the REC. The EPA’s 

definition in the rule was developed to 

account for these factors. 

We further disagree with the 

petitioners’ assertion that the EPA 

definition is too complicated. We 

believe that values for each of the three 

parameters discussed above and used in 

the EPA definition are known by 

operators in advance of flowback and 

that the relatively simple calculation 

called for in the EPA definition could be 

performed with a basic hand-held 

calculator and should not pose 

difficulty or hardship for smaller 

operators. For these reasons, we are 

finalizing the definition of ‘‘low 

pressure gas well’’ as proposed. 

Comment: A commenter concurs with 

the industry’s alternate definition 

presented in the previous comment. The 

commenter explains that typical gas 

wells in Kentucky are produced from 

low pressure reservoirs with low 

permeability. In order to make them 

economically productive, they are 

stimulated with treatments that contain 

very little fluid. According to the 

commenter, all Devonian Shale wells— 

the largest producing reservoir in 

eastern Kentucky—are currently treated 

using straight nitrogen. Most nitrogen 

flowbacks require a minimum of 3 days 

before there is a sufficient volume of 

natural gas to route and flare with a 

combustion device. Fluid treatments or 

‘‘foamed’’ fluid are almost certain to 

damage the formation’s permeability, 

negating the opportunity for Kentucky’s 

producers to continue developing that 

region’s significant resources. 

The commenter states that the current 

EPA definition of a ‘‘low pressure well’’ 

is based upon the physical 

characteristics of a reservoir, which is 


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then compared to the poorly defined 

‘‘flow line pressure at the sales meter.’’ 

Typical gathering systems in eastern 

Kentucky are low pressure—typically 

below 100 psi with the overwhelming 

majority below 50 psi. This makes 

qualifying as a ‘‘low pressure well’’ 

under the current definition almost 

impossible in Kentucky. 

According to the commenter, if a 

Devonian Shale well cannot be qualified 

as ‘‘low pressure’’ after January 1, 2015, 

Kentucky operators will be denied the 

option of stimulating gas wells with an 

‘‘inert’’ gas such as nitrogen. Without 

the ‘‘low pressure’’ qualification, the 

requirement of a green completion 

eliminates the ability to flow the wells 

back to the atmosphere to remove the 

nitrogen used in the stimulation. The 

commenter predicts that drilling in 

Kentucky’s Appalachian region will 

cease unless the EPA adopts the 

proposed alternative ‘‘low pressure 

well’’ definition. 

Response: We believe the commenter 

may be misinterpreting the proposed 

rule. The commenter appears to 

interpret the rule language as requiring 

liquids to be used for stimulating the 

well. This is not the case. The owner or 

operator is free to use any stimulation 

procedure so long as the handling of the 

liquids and gases released from the well 

follows the rule’s provisions. 

Based on the comment, it appears that 

there will be essentially little or no 

liquids discharged from these wells 

during the completion process, and that 

the initial flowback period would 

consist of the period of nitrogen 

flowback that precedes the production 

of natural gas. There is nothing in the 

NSPS that prohibits venting of nitrogen. 

However, any liquids that are 

discharged would have to be handled as 

specified in the rule. The commenter 

does not appear to be concerned about 

these rule provisions. 

The problem appears to be related to 

the rule provisions that require the 

operator to route the recovered gas to a 

gas flow line or collection system, reinject the recovered gas into the well or 

another well, use the recovered gas as 

an on-site fuel source or use the 

recovered gas for another useful purpose 

that a purchased fuel or raw material 

would serve. As explained above, the 

final amendments clarify that during the 

initial flowback stage, gas may be 

vented. It appears that the types of 

completions discussed by the 

commenter do not have a separation 

flowback stage (based on the limited 

recovered liquids), and once the 

nitrogen stimulation gas is off-gassed, 

the well goes directly to production. If 

this is the case, there should not be 

excessive back pressure introduced by 

the separator and other flowback 

equipment that would overly impede 

gas flow, which was the situation the 

EPA was intending to avoid by 

providing exemptions for low pressure 

gas wells. As a result, as described by 

the commenter, we believe that such 

wells do not need a low pressure well 

exemption to enable them to be 

completed and to startup production. 

We note that, even if there is no initial 

flowback stage or separation flowback 

stage as defined by the rule, then the 

completion is still subject to the 

requirements of § 60.5375(a)(2) through 

(4). 

If completion operations on these 

wells do in fact involve a separation 

flowback stage, then § 60.5375(a)(1)(ii) 

would apply, meaning that during the 

separation flowback stage, all salable gas 

must be routed to the flow line and that, 

if it is infeasible to route the recovered 

gas to a flow line or collection system, 

reinject the gas or use the gas as fuel or 

for other useful purpose, the recovered 

gas must be combusted. No direct 

venting of recovered gas is allowed 

during the separation flowback stage. 

In the case of the Devonian shale 

wells, we understand that the initial gas 

flow is predominantly nitrogen which is 

not combustible. However, based on the 

initial flowback provisions under the 

final rule, these gases would be allowed 

to be vented during initial flowback. It 

is assumed that as the nitrogen 

stimulant gas is released from the well, 

the hydrocarbon proportion of 

recovered gas will continually increase 

and eventually become combustible. 

Therefore, based on the above rationale, 

we do not agree that these wells should 

be specifically exempted as low 

pressure wells. 

B. Storage Vessels 

Comment: One commenter believes 

the proposed definition of ‘‘removed 

from service’’ is too narrow. The 

commenter suggests that a storage vessel 

affected facility should be considered 

removed from service if it no longer 

meets the definition of a storage vessel, 

regardless of whether it is physically 

isolated and disconnected from the 

process. As proposed, the commenter 

contends that the rule addresses only a 

single scenario when a storage vessel is 

no longer used to store any materials. 

However, there are many other 

scenarios where a storage vessel affected 

facility may still be used for storage but 

no longer meets the definition of storage 

vessel and would thus no longer be 

subject to the rule requirements. 

Examples of such scenarios provided by 

the commenter include an atmospheric 

condensate tank converted to methanol 

storage or non-VOC storage which may 

need to be connected to the process; a 

bullet tank previously operated as an 

atmospheric condensate tank for which 

its service is subsequently changed to 

pressurized storage of butane and is 

connected to the process; and a bullet 

tank previously operated as an 

atmospheric produced water tank and 

which its service is subsequently 

changed to a surge control process 

vessel and is connected to the process. 

For the scenario where a storage 

vessel is no longer used to store 

anything, the commenter contends that 

the language regarding physical 

isolation and disconnection is not 

necessary because the definition of 

storage vessel states, ‘‘vessel that 

contains an accumulation of crude oil, 

condensate, intermediate hydrocarbon 

liquids, or produced water . . .’’ Thus, 

if those materials were to again enter the 

storage vessel, the vessel would be 

‘‘returned to service’’ and subject to the 

applicable requirements. The 

commenter points out that in the unique 

scenario where a storage vessel is no 

longer used to store anything, physical 

isolation is sufficient; disconnection 

should not be required if, for example, 

blind flanges are installed. The 

commenter suggests several changes to 

the definition of removed from service 

to cover all scenarios where a storage 

vessel may no longer meet the definition 

of storage vessel for purposes of subpart 

OOOO, but is still used for storage of 

liquids not included in the definition of 

‘‘storage vessel.’’ 

Another commenters recommends 

that the EPA separate the definition of 

returned to service from the definition 

of removed from service and provided 

suggested language. 

Response: We agree that the proposed 

definition of ‘‘removed from service’’ 

did not sufficiently address the many 

scenarios identified by the commenters. 

In particular, the scenario where a 

storage vessel affected facility is 

removed from service for a period of 

time and then returned to service for 

some purpose was not clearly addressed 

under the proposed rule. As discussed 

further in section IV.B of this preamble, 

we have revised the definition of 

‘‘removed from service’’ and added a 

definition for ‘‘returned to service.’’ 

Comment: Several commenters do not 

support the concept of a storage vessel 

maintaining its subpart OOOO 

applicability status when that storage 

vessel is relocated to a different well 

site. One commenter stated that storage 

vessel PTE at a previous location is 

irrelevant to the new location and is 

entirely dependent on the particular 


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type of service for which the vessel is 

being used at the new location. The 

commenters point out that the 

emissions from storage vessels are not 

related to the equipment itself, but 

rather the characteristics and volume of 

the fluids being sent to and stored in the 

storage vessel. 

As proposed, the commenters believe 

that the rule could require an operator 

to control a storage vessel with little 

actual emissions and could discourage 

the replacement of older damaged 

storage vessels with newer vessels that 

may have come from a location that had 

emissions above the 6 tpy threshold. 

One commenter concurred that 

applicability should be based on the 

type of liquids introduced into the 

relocated storage vessel and the 

emissions, not just the type of liquids. 

The commenters seek confirmation that 

applicability of storage vessels is 

triggered by the addition of crude oil, 

condensate, produced water or 

intermediate hydrocarbon liquids to the 

vessel and the unique production of the 

new location, rather than by simply 

moving the vessel to a new location. 

The commenters believe the proposed 

rule requirements are further 

complicated if the out-of-service storage 

vessel is sold to another owner or 

operator as part of the relocation. ‘‘Tank 

pedigree’’ tracking would quickly 

become unduly burdensome. The 

commenter agrees that if the vessel’s 

emissions are above 6 tpy at the new 

location, it should be fully subject to the 

rule. The commenters believe that the 

tracking and recordkeeping burden of 

having to assess different emissions 

thresholds on different affected facility 

storage vessels based solely on their 

movement within the company is an 

excessive and unrealistic burden, 

particularly where the storage vessel 

emissions are less than 6 tpy at the new 

location. At this point, according to the 

commenters, the tank is no longer a 

storage vessel affected facility and 

should not be subject to the rule’s 

requirements, including annual 

reporting, regardless of whether the 

storage vessel’s previous owner/operator 

used the vessel in a service at a different 

location and facility, which resulted in 

emissions sufficient to trigger rule 

applicability. Unless the storage vessel’s 

emissions are above 6 tpy at the new 

location, the commenters contend that 

subpart OOOO requirements should not 

be imposed on a relocated storage 

vessel. 

One commenter requests that controls 

only be required when that relocated 

tank’s emissions exceed 6 tpy, and not 

merely 4 tpy as required in 

§ 60.5395(f)(2)(ii)(B). The commenter 

does not understand why the initial 

emissions assessment should be 

different for a relocated storage vessel 

compared to a newly constructed 

storage vessel. The commenter states 

that the hydrocarbon composition 

flowing through the relocated storage 

vessel may be significantly different at 

the new location, and the owner or 

operator of the storage vessel should not 

be penalized with a lower emissions 

threshold. The commenter points out 

that a storage vessel affected facility is 

defined as ‘‘a single storage vessel . . . 

that has the potential for VOC emissions 

equal to or greater than 6 tpy . . . 

[taking] into account requirements 

under a legally and practically 

enforceable limit . . .’’ The commenter 

contends that by requiring a 4 tpy 

threshold for relocated affected facility 

storage vessels, the EPA is effectively 

requiring control devices on storage 

vessels that have emissions below the 

threshold that is cost effective to 

control. Therefore, the commenter 

contends that a 4 tpy threshold for 

relocated affected facility storage vessels 

is legally unsupportable. 

Finally, another commenter seeks 

clarification on the requirements for 

storage vessels that are returned to 

service at the same location. In the 

September 23, 2013 final rule 

amendments, the EPA added 

requirements at § 60.5395(f)(2)(ii)(B), 

which states that ‘‘[i]f the uncontrolled 

VOC emissions without considering 

control from your storage vessel affected 

facility are 4 tpy or greater, you must 

comply with paragraph (d) of this 

section within 60 days of returning to 

service.’’ However, the commenter 

points out that storage vessel affected 

facilities returned to service with 

uncontrolled emissions less than 4 tpy 

are not addressed and the commenter 

seeks clarification of this issue. 

Response: We agree with the 

commenters’ assertion that the 

emissions from a storage vessel are not 

intrinsic to the vessel but are a result of 

the operation and service to which the 

storage vessel is connected. We have 

provided a detailed discussion of this 

issue and the final amendments for 

storage vessels that are removed from 

service and returned from service in 

section IV.B. 

Comment: Several commenters 

expressed general support for allowing 

the use of electronic spark ignition 

systems on combustion control devices, 

although many of the commenters also 

suggested modifications to the proposed 

requirements. 

One commenter notes that Colorado’s 

Regulation Number 7 requires all 

combustion devices used to control 

hydrocarbon emissions utilize an autoigniter to ensure the operation of the 

continuous flame pilot. During the 

adoption of this requirement, the 

Colorado Air Quality Control 

Commission determined that autoigniters were a cost-effective method to 

reduce hydrocarbon emissions. Another 

commenter notes that the Fort Berthold 

Indian Reservation Federal 

Implementation Plan allows for the use 

of continuous pilots or automatic spark 

igniters. 

Three commenters note that in the 

Natural Gas STAR program, the EPA 

published a Partner Recognized 

Opportunity (PRO) in PRO Fact Sheet 

No. 903 that discusses the operation and 

benefits of electronic spark ignition 

systems. The commenter contends that 

the EPA should not lose the benefits of 

this control technology enhancement by 

disallowing its use in this rule. With 

this being an established technology in 

Natural Gas STAR, the commenters do 

not believe operators should have to 

petition the EPA for approval under its 

new control technology provision. The 

commenters request that the rule be 

modified to explicitly allow the use of 

electronic spark ignition systems as an 

alternative to a continuous pilot flame. 

The commenters add that in the arctic 

environment in Alaska, operators have 

often encountered situations where, 

following maintenance on a flare, a new 

spark igniter with frost buildup cannot 

re-light the flare pilot. Continuous pilot 

flames are required for safety and 

certainty of combustion in arctic Alaska. 

Therefore, the commenters contend that 

if an electronic spark ignition system is 

allowed, it needs to be an option, rather 

than a requirement. Two other 

commenters agree that it should only be 

an option. 

One commenter believes that spark 

ignition systems may be most 

appropriate for flares which only 

occasionally operate (such as flares to 

handle mishap/safety shutdowns, 

maintenance blowdowns, etc.) and 

flares that operate more or less 

continuously, such as a flare for a wet 

seal compressor seal-degassing unit. In 

both cases they may be more reliable 

than a pilot light, since spark ignition 

systems cannot be blown out and do not 

consume fuel and increase emissions, as 

a pilot light does. However, the 

commenter contends that a spark 

ignition system should not be the sole 

ignition mechanism for flares with 

highly variable flow, such as flares 

associated with well completion 

flowback or storage tank control 

systems. The commenter states that 

variable flow can lead to sputtering 

flames, and a failure to burn all the gas 


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directed to the flare, leading to large 

emissions of VOC and methane from the 

flare. The commenter is concerned that 

a spark ignition device may not restart 

the flare as rapidly as a pilot light in 

such situations, which could lead to 

higher emissions for flares on variable 

flow sources such as wells and storage 

tanks. Given the high rate of emissions 

of VOC and methane during flowback 

flaring, it would be appropriate to 

require both pilot lights and spark 

ignition devices. 

One commenter adds that although 

they believe electronic spark ignition 

systems should be allowed as an option, 

the EPA has not provided any evidence 

or data to suggest that pilots do not 

remain continuously lit during 

operation in the applications used for 

compliance with this rule. Nor has the 

EPA provided any data on potential 

environmental benefit of such 

technology. The commenter also 

contends that safety implications must 

be seriously considered when using 

auto-igniters. When use is appropriate, 

operators must be able to tailor the autoigniter configuration and operation to 

the combustion device, the facility 

design, the flammability of the waste 

stream, facility operations and 

applicable industry standards. The 

commenter states that the EPA should 

not attempt to create a blanket mandate 

for the application or operation of autoigniters since safety risks must be 

evaluated, often on a case-by-case basis. 

Auto-igniters may not be appropriate or 

allowed in current industry standards 

for all applications (such as heaters, 

boilers, and enclosed combustors). The 

commenter provides details of safety 

concerns related to electronic spark 

ignition systems in their comments. 

Two commenters recommend that 

electronic spark ignition systems have 

fail safe systems such as temperature 

and pressure monitoring to prevent any 

venting during periods when vapors are 

flowing to the device. 

One commenter points out that 

electronic spark ignition systems have 

been available for over twenty years and 

have a proven track record of 

successfully and safely lighting and 

maintaining flares and fuel burning 

equipment. 

Response: In our response to 

comments on the 2011 proposed rule, 

we stated that given the intermittent and 

inconsistent nature of emissions from 

storage vessels in this industry 

combined with the highly variable VOC 

concentration in the emissions, we did 

not believe at that time that a sparkignited flare would achieve the same 

level of emission reduction as a flare 

with a continuous flame present. 

In the July 17, 2014, proposed rule, 

we solicited information, including any 

test data or other documentation, that 

may help address the following topics 

relative to the operation of an electronic 

spark ignition: (1) Appropriate design, 

operation and maintenance procedures 

to ensure proper combustion of the 

waste stream; (2) use of safety valves to 

ensure that no gas is available for 

combustion if the ignition system is not 

functional; (3) measures that could be 

taken to avoid vapor venting upstream 

of the control device in cases where the 

safety valve remains closed; (4) 

frequency of monitoring for proper 

operation; (5) specific checks to be made 

to ensure proper operation; (6) operating 

parameters that affect pilot-less flare 

performance and flare flame stability; 

(7) effects of gas with low BTU content 

or gas of variable VOC content; and (8) 

how often these systems need to be 

replaced. 

In addition, we were interested in 

information on the use of this 

technology as a means of ensuring that 

continuous flame pilots remain 

functional at all times. Therefore, we 

also solicited comment, including any 

supporting data or information, on 

whether automatic spark ignition 

relighting systems should be required as 

a means of ensuring that continuous 

flame pilots remain functional at all 

times. 

Although we received some 

information, we received no data in 

response to most of the questions we 

asked that would help us determine that 

electronic spark ignition should be 

allowed as an alternative to a 

continuous pilot flame. 

Accordingly, issues and concerns 

related to intermittent and inconsistent 

flow still remain. Specifically, we 

remain concerned with how quickly an 

electronic spark ignition system will 

ignite an emission stream from an 

intermittent and inconsistent emission 

source. We also remain to have concerns 

about flame stability. 

In light of the comments received and 

the lack of information received in 

response to our solicitation, we are not 

satisfied at this time that we have 

sufficient information on which to base 

a decision to allow electronic spark 

ignition as an alternative to a 

continuous pilot flame. 

C. Routing of Reciprocating Compressor 

Rod Packing Emissions to a Process 

Comment: One commenter expressed 

support for the EPA’s proposal to allow 

reciprocating compressor rod packing 

emissions to be routed to a process. 

However, the commenter claims that 

they cannot comply with the structure 

of the requirements as proposed. Also, 

the commenter contends that the 

proposed requirements do not conform 

to the current structure of the rule. The 

commenter recommends several 

changes: 

First, the commenter states that 

proposed § 60.5385(a)(3) references 

initial compliance requirements with 

§ 60.5411(a) and (b), which is 

unnecessary and inconsistent with 

§ 60.5385(a)(1) and (2). The commenter 

also believes it is inconsistent with the 

rule’s structure for other affected 

facilities. 

Second, the commenter states that the 

EPA is not proposing to modify 

§ 60.5410(c)(1) (initial compliance 

requirements) which states ‘‘[d]uring the 

initial compliance period, you must 

continuously monitor the number of 

hours of operation or track the number 

of months since the last rod packing 

replacement.’’ The commenter contends 

that reciprocating compressor affected 

facilities complying with § 60.5385(a)(3) 

cannot comply with this requirement. 

Thus, the commenter believes that this 

requirement must be revised. 

Additionally, the commenter contends 

that there is not an initial compliance 

requirement here for compressors 

complying with § 60.5385(a)(3); thus, it 

would be inappropriate to reference the 

§ 60.5411(a) and (b) requirements. 

Third, the commenter states that in 

the proposed continuous compliance 

requirements in § 60.5415(c)(4), the EPA 

proposes to reference the initial 

compliance requirements in § 60.5411(a) 

and (b). The commenter contends that 

this does not make sense and does not 

conform to the changes that the EPA is 

also proposing at § 60.5416(a) and (b) 

(continuous cover and closed vent 

system requirements). 

Fourth, the commenter states that the 

EPA is proposing to make § 60.5416(a) 

and (b) (continuous cover and closed 

vent system requirements) applicable 

for reciprocating compressors; however, 

the recordkeeping requirements 

associated with § 60.5416(a) and (b) 

have not been modified to conform to 

this proposed change. Additionally, the 

commenter believes § 60.5420(c)(6) 

currently fails to reference 

§ 60.5416(a)(2). The commenter 

recommends that the EPA take this 

opportunity to resolve this oversight. 

One commenter does not believe that 

the proposed application of the closed 

vent system requirements to 

reciprocating compressors or the routing 

of the rod packing equipment through a 

closed vent system to a process in 

§ 60.5385(a)(3) are appropriate 

alternatives. 


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4Memorandum from Moore, Bruce, U.S. EPA, to 

Docket ID No. EPA–HQ–OAR–2010–0505, 

Technical Corrections to the Oil and Natural Gas 

Sector New Source Performance Standards. June 

30, 2014. 

Response: The EPA disagrees with 

several aspects of the comments but also 

agrees with certain suggestions. The 

commenter states that the reference in 

§ 60.5385(a)(3) to § 60.5411(a) and (b) is 

not necessary. The EPA disagrees with 

this comment, because we consider it 

necessary to specify the standards to 

which a closed vent system and cover 

must be designed and operated to 

achieve the emission reductions sought 

by the rule. 

The EPA disagrees with the comment 

that the reference to § 60.5411(a) and (b) 

make it inconsistent with § 60.5385(a)(1) 

and (2). Neither § 60.5385(a)(1) nor (2) 

relies on additional equipment (e.g., 

covers and closed vent systems) to be 

operated properly to obtain the required 

emission reductions. Therefore, no such 

reference is needed in § 60.5385(a)(1) or 

(2). 

The EPA agrees that compliance with 

60.5410(c)(1) is intended for owners and 

operators that have not exercised their 

option to comply with 60.5385(a)(3), 

and has finalized language to that effect 

suggested by the commenter. The EPA 

has added a restrictive clause to 

§ 60.5410(c) such that § 60.5410(c)(1) 

through (4) apply only to sources 

electing to comply with § 60.5385(a)(1) 

and (2). We made this change because 

several of the provisions of 

§ 60.5410(c)(1) through (4) are 

inappropriate for affected facilities that 

have chosen to comply with 

§ 60.5385(a)(3) rather than (a)(1) and (2). 

The EPA agrees that owners and 

operators that route rod packing 

emissions to a process under 

§ 60.5385(a)(3) are not subject to 

§ 60.5410(c)(1). We have amended 

§ 60.5410(c) to specify that owners and 

operators using closed vent systems and 

covers are not subject to § 60.5410(c)(1). 

The commenter states that 

requirements in § 60.5411(a) and (b) are 

initial compliance requirements and 

should not be referenced in the 

continuous compliance requirements of 

§ 60.5415(c)(4). The EPA disagrees with 

the commenter because there are 

requirements within § 60.5411(a) and (b) 

that require compliance beyond initial 

compliance. Therefore, we believe it is 

necessary to specify continuous 

compliance with § 60.5411(a) and (b). 

The commenter states that 

§ 60.5416(a) and (b) should be qualified 

so as to apply only the reciprocating 

compressors subject to § 60.5385(a)(3). 

The EPA agrees with this comment and 

has added language to make this change. 

The EPA agrees that § 60.5415(c)(4) is 

intended to describe the requirements 

applicable to reciprocating compressors 

operating under § 60.5385(a)(3) and 

should refer to the continuous 

compliance requirements applicable to 

closed vent systems and covers 

specified in § 60.5416(a) and (b). 

The EPA agrees with the suggested 

revision of 60.5420(c) (6) through (9), 

and has made the changes to the 

regulatory text. 

Comment: One commenter also 

expressed support for the proposed 

changes to § 60.5385 to allow the 

emissions from reciprocating 

compressors to be routed to a process, 

but believes other revisions, similar to 

or the same as those suggested by the 

previous commenter, are needed in the 

rule to maintain consistency with the 

proposed changes. The commenter’s 

suggestions are not repeated here but are 

detailed in their comments. 

Response: As discussed in the 

response to a previous comment, the 

EPA has made several amendments to 

the proposed rule language to clarify the 

requirements for reciprocating 

compressors. 

VI. Technical Corrections and 

Clarifications 

The EPA is finalizing corrections and 

clarifications to the 2012 NSPS and the 

2013 storage vessel amendments 

including typographical and 

grammatical errors, as well as incorrect 

dates and cross-references. Details of the 

specific changes we are finalizing to the 

regulatory text may be found in the 

docket for this action.4

VII. Impacts of These Final 

Amendments 

Our analysis shows that owners and 

operators of affected facilities would 

choose to install and operate the same 

or similar air pollution control 

technologies under this action as would 

have been necessary to meet the 

previously finalized standards. We 

project that these amendments will 

result in no significant change in costs, 

emission reductions, or benefits. Even if 

there were changes in costs for the 

affected facilities, such changes would 

likely be small relative to both the 

overall costs of the individual projects 

and the overall costs and benefits of the 

final rule. Since we believe that owners 

and operators would put on the same 

controls for this revised final rule that 

they would have for the original final 

rule, there should not be any 

incremental costs related to this final 

revision. 

A. What are the air impacts? 

We believe that owners and operators 

of affected facilities will install the same 

or similar control technologies to 

comply with the revised standards 

finalized in this action as they would 

have installed to comply with the 

previously finalized standards. 

Accordingly, we believe that this final 

rule will not result in significant 

changes in emissions of any of the 

regulated pollutants. 

B. What are the energy impacts? 

This final rule is not anticipated to 

have an effect on the supply, 

distribution, or use of energy. As 

previously stated, we believe that 

owners and operators of affected 

facilities would install the same or 

similar control technologies as they 

would have installed to comply with the 

previously finalized standards. 

C. What are the compliance costs? 

We believe there will be no significant 

change in compliance costs as a result 

of this final rule because owners and 

operators of affected facilities would 

install the same or similar control 

technologies as they would have 

installed to comply with the previously 

finalized standards. 

D. What are the economic and 

employment impacts? 

Because we expect that owners and 

operators of affected facilities would 

install the same or similar control 

technologies to meet the standards 

finalized in this action as they would 

have chosen to comply with the 

previously finalized standards, we do 

not anticipate that this final rule will 

result in significant changes in 

emissions, energy impacts, costs, 

benefits, or economic impacts. Likewise, 

we believe this rule will not have any 

impacts on the price of electricity, 

employment or labor markets, or the 

U.S. economy. 

E. What are the benefits of the final 

standards? 

As previously stated, the EPA 

anticipates the oil and natural gas sector 

will not incur significant compliance 

costs or savings as a result of this action 

and we do not anticipate any significant 

emission changes resulting from these 

amendments to the rule. Therefore, 

there are no direct monetized benefits or 

disbenefits associated with this final 

rule. 

VIII. Statutory and Executive Order 

Reviews 

Additional information about these 

statutes and Executive Orders can be 


tkelley on DSK3SPTVN1PROD with RULES3
79036 Federal Register / Vol. 79, No. 250 / Wednesday, December 31, 2014 / Rules and Regulations 

found at http://www2.epa.gov/lawsregulations/laws-and-executive-orders. 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This action is not a significant 

regulatory action and was therefore not 

submitted to the Office of Management 

and Budget (OMB) for review. 

B. Paperwork Reduction Act (PRA) 

This action does not impose any new 

information collection burden under the 

PRA. OMB has previously approved the 

information collection activities 

contained in the existing regulations 

and has assigned OMB control number 

2060–0673. Today’s action does not 

change the information collection 

requirements previously finalized and, 

as a result, does not impose any 

additional information collection 

burden on industry. 

C. Regulatory Flexibility Act (RFA) 

I certify that this action will not have 

a significant economic impact on a 

substantial number of small entities 

under the RFA. In making this 

determination, the impact of concern is 

any significant adverse economic 

impact on small entities. An agency may 

certify that a rule will not have a 

significant economic impact on a 

substantial number of small entities if 

the rule relieves regulatory burden, has 

no net burden or otherwise has a 

positive economic effect on the small 

entities subject to the rule. The EPA has 

determined that none of the small 

entities subject to this rule will 

experience a significant impact because 

today’s action imposes no additional 

compliance costs on owners or 

operators of affected sources. We have 

therefore concluded that this action will 

have no net regulatory burden for all 

directly regulated small entities. 

D. Unfunded Mandates Reform Act of 

1995 (UMRA) 

This action does not contain any 

unfunded mandate as described in 

UMRA, 2 U.S.C. 1531–1538, and does 

not significantly or uniquely affect small 

governments. This action imposes no 

enforceable duty on any state, local or 

tribal governments or the private sector. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications as specified in Executive 

Order 13175. It will not have substantial 

direct effect on tribal governments, on 

the relationship between the federal 

government and Indian tribes or on the 

distribution of power and 

responsibilities between the federal 

government and Indian tribes, as 

specified in Executive Order 13175. 

Thus, Executive Order 13175 does not 

apply to this action. 

Although at proposal the EPA noted 

that Executive Order 13175 did not 

apply, the EPA solicited comment from 

tribes inclined to comment on the 

proposed action. The EPA did not 

receive substantive comments from 

tribes on our proposal. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

This action is not subject to Executive 

Order 13045 because it is not 

economically significant as defined in 

Executive Order 12866, and because the 

EPA does not believe the environmental 

health or safety risks addressed by this 

action present a disproportionate risk to 

children. 

This action does not add to or relieve 

affected sources from any requirements, 

and therefore has no impacts; thus, 

health and risk assessments were not 

conducted. The public was invited to 

submit comments or identify peerreviewed studies and data that assess 

effects of early life exposure to HAP 

from oil and natural gas sector activities. 

The EPA received no substantive 

information on these risks. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211 because it is not a 

significant regulatory action under 

Executive Order 12866. 

I. National Technology Transfer and 

Advancement Act (NTTAA) 

This rulemaking does not involve 

technical standards. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

The EPA believes the human health or 

environmental risk addressed by this 

action will not have potential 

disproportionately high and adverse 

human health or environmental effects 

on minority, low-income or indigenous 

populations because it does not affect 

the level of protection provided to 

human health or the environment. The 

basis for this determination is that this 

action is a reconsideration of existing 

requirements and imposes no new 

impacts or costs. 

K. Congressional Review Act (CRA) 

This action is subject to the CRA, and 

the EPA will submit a rule report to 

each House of the Congress and to the 

Comptroller General of the United 

States. This action is not a ‘‘major rule’’ 

as defined by 5 U.S.C. 804(2). 

List of Subjects in 40 CFR Part 60 

Administrative practice and 

procedure, Air pollution control, 

Environmental protection, 

Intergovernmental relations, Reporting 

and recordkeeping. 

Dated: December 19, 2014. 

Gina McCarthy, 

Administrator. 

For the reasons set out in the 

preamble, title 40, chapter I of the Code 

of Federal Regulations is amended as 

follows: 

PART 60—STANDARDS OF 

PERFORMANCE FOR NEW 

STATIONARY SOURCES 

■ 1. The authority citation for part 60 

continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

Subpart OOOO—[Amended] 

■ 2. Section 60.5365 is amended by 

revising paragraph (e) to read as follows: 

§ 60.5365 Am I subject to this subpart? 

* * * * * 

(e) Each storage vessel affected 

facility, which is a single storage vessel 

located in the oil and natural gas 

production segment, natural gas 

processing segment or natural gas 

transmission and storage segment, and 

has the potential for VOC emissions 

equal to or greater than 6 tpy as 

determined according to this section by 

October 15, 2013 for Group 1 storage 

vessels and by April 15, 2014, or 30 

days after startup (whichever is later) for 

Group 2 storage vessels, except as 

provided in paragraphs (e)(1) through 

(4) of this section. The potential for VOC 

emissions must be calculated using a 

generally accepted model or calculation 

methodology, based on the maximum 

average daily throughput determined for 

a 30-day period of production prior to 


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the applicable emission determination 

deadline specified in this section. The 

determination may take into account 

requirements under a legally and 

practically enforceable limit in an 

operating permit or other requirement 

established under a Federal, State, local 

or tribal authority. 

(1) For each new, modified or 

reconstructed storage vessel receiving 

liquids pursuant to the standards for gas 

well affected facilities in § 60.5375, 

including wells subject to § 60.5375(f), 

you must determine the potential for 

VOC emissions within 30 days after 

startup of production. 

(2) A storage vessel affected facility 

that subsequently has its potential for 

VOC emissions decrease to less than 6 

tpy shall remain an affected facility 

under this subpart. 

(3) For storage vessels not subject to 

a legally and practically enforceable 

limit in an operating permit or other 

requirement established under Federal, 

state, local or tribal authority, any vapor 

from the storage vessel that is recovered 

and routed to a process through a VRU 

designed and operated as specified in 

this section is not required to be 

included in the determination of VOC 

potential to emit for purposes of 

determining affected facility status, 

provided you comply with the 

requirements in paragraphs (e)(3)(i) 

through (iv) of this section. 

(i) You meet the cover requirements 

specified in § 60.5411(b). 

(ii) You meet the closed vent system 

requirements specified in § 60.5411(c). 

(iii) You maintain records that 

document compliance with paragraphs 

(e)(3)(i) and (ii) of this section. 

(iv) In the event of removal of 

apparatus that recovers and routes vapor 

to a process, or operation that is 

inconsistent with the conditions 

specified in paragraphs (e)(3)(i) and (ii) 

of this section, you must determine the 

storage vessel’s potential for VOC 

emissions according to this section 

within 30 days of such removal or 

operation. 

(4) For each new, reconstructed, or 

modified storage vessel with startup, 

startup of production, or which is 

returned to service, affected facility 

status is determined as follows: If a 

storage vessel is reconnected to the 

original source of liquids; used to 

replace any storage vessel affected 

facility; or is installed in parallel with 

any storage vessel affected facility, it is 

a storage vessel affected facility subject 

to the same requirements as before being 

removed from service, or applicable to 

the storage vessel affected facility being 

replaced, or with which it is installed in 

parallel immediately upon startup, 

startup of production, or return to 

service. 

* * * * * 

■ 3. Section 60.5375 is amended by: 

■ a. Revising paragraphs (a) 

introductory text and (a)(1) through (3); 

■ b. Revising paragraph (b); 

■ c. Revising paragraphs (f)(1)(i) and (ii); 

and 

■ d. Revising paragraph (f)(2). 

The revisions read as follows: 

§ 60.5375 What standards apply to gas 

well affected facilities? 

* * * * * 

(a) Except as provided in paragraph (f) 

of this section, for each well completion 

operation with hydraulic fracturing 

begun prior to January 1, 2015, you 

must comply with the requirements of 

paragraphs (a)(3) and (4) of this section 

unless a more stringent state or local 

emission control requirement is 

applicable; optionally, you may comply 

with the requirements of paragraphs 

(a)(1) through (4) of this section. For 

each new well completion operation 

with hydraulic fracturing begun on or 

after January 1, 2015, you must comply 

with the requirements in paragraphs 

(a)(1) through (4) of this section. You 

must maintain a log as specified in 

paragraph (b). 

(1) For each stage of the well 

completion operation, as defined in 

§ 60.5430, follow the requirements 

specified in paragraph (a)(1)(i) and (ii) 

of this section. 

(i) During the initial flowback stage, 

route the flowback into one or more 

well completion vessels or storage 

vessels and commence operation of a 

separator unless it is technically 

infeasible for a separator to function. 

Any gas present in the initial flowback 

stage is not subject to control under this 

section. 

(ii) During the separation flowback 

stage, route all recovered liquids from 

the separator to one or more well 

completion vessels or storage vessels, 

re-inject the liquids into the well or 

another well or route the recovered 

liquids to a collection system. Route the 

recovered gas from the separator into a 

gas flow line or collection system, reinject the recovered gas into the well or 

another well, use the recovered gas as 

an on-site fuel source, or use the 

recovered gas for another useful purpose 

that a purchased fuel or raw material 

would serve. If it is infeasible to route 

the recovered gas as required above, 

follow the requirements in paragraph 

(a)(3) of this section. If, at any time 

during the separation flowback stage, it 

is not technically feasible for a separator 

to function, you must comply with 

(a)(1)(i) of this section. 

(2) All salable quality recovered gas 

must be routed to the gas flow line as 

soon as practicable. In cases where 

salable quality gas cannot be directed to 

the flow line, you must follow the 

requirements in paragraph (a)(3) of this 

section. 

(3) You must capture and direct 

recovered gas to a completion 

combustion device, except in conditions 

that may result in a fire hazard or 

explosion, or where high heat emissions 

from a completion combustion device 

may negatively impact tundra, 

permafrost or waterways. Completion 

combustion devices must be equipped 

with a reliable continuous ignition 

source. 

* * * * * 

(b) You must maintain a log for each 

well completion operation at each gas 

well affected facility. The log must be 

completed on a daily basis for the 

duration of the well completion 

operation and must contain the records 

specified in § 60.5420(c)(1)(iii). 

* * * * * 

(f) * * * 

(1) * * * 

(i) Each well completion operation 

with hydraulic fracturing at a wildcat or 

delineation well. 

(ii) Each well completion operation 

with hydraulic fracturing at a nonwildcat low pressure gas well or nondelineation low pressure gas well. 

(2) Route the flowback into one or 

more well completion vessels and 

commence operation of a separator 

unless it is technically infeasible for a 

separator to function. Any gas present in 

the flowback before the separator can 

function is not subject to control under 

this section. You must capture and 

direct recovered gas to a completion 

combustion device, except in conditions 

that may result in a fire hazard or 

explosion, or where high heat emissions 

from a completion combustion device 

may negatively impact tundra, 

permafrost or waterways. Completion 

combustion devices must be equipped 

with a reliable continuous ignition 

source. You must also comply with 

paragraphs (a)(4) and (b) through (e) of 

this section. 

* * * * * 

■ 4. Section 60.5385 is amended by: 

■ a. Revising paragraph (a) introductory 

text; and 

■ b. Adding paragraph (a)(3). 

The revision and addition read as 

follows: 

§ 60.5385 What standards apply to 

reciprocating compressor affected 

facilities? 

* * * * * 


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79038 Federal Register / Vol. 79, No. 250 / Wednesday, December 31, 2014 / Rules and Regulations 

(a) You must replace the reciprocating 

compressor rod packing according to 

either paragraph (a)(1) or (2) of this 

section or you must comply with 

paragraph (a)(3) of this section. 

* * * * * 

(3) Collect the emissions from the rod 

packing using a rod packing emissions 

collection system which operates under 

negative pressure and route the rod 

packing emissions to a process through 

a closed vent system that meets the 

requirements of § 60.5411(a). 

* * * * * 

■ 5. Section 60.5390 is amended by 

revising paragraph (c)(2) to read as 

follows: 

§ 60.5390 What standards apply to 

pneumatic controller affected facilities? 

* * * * * 

(c) * * * 

(2) Each pneumatic controller affected 

facility constructed, modified or 

reconstructed on or after October 15, 

2013, at a location between the 

wellhead and a natural gas processing 

plant or the point of custody transfer to 

an oil pipeline must be tagged with the 

month and year of installation, 

reconstruction or modification, and 

identification information that allows 

traceability to the records for that 

controller as required in 

§ 60.5420(c)(4)(iii). 

* * * * * 

■ 6. Section 60.5395 is amended by: 

■ a. Revising paragraph (d)(1)(i); and 

■ b. Revising paragraph (f). 

The revisions read as follows: 

§ 60.5395 What standards apply to storage 

vessel affected facilities? 

* * * * * 

(d) * * * 

(1) * * * 

(i) For each Group 2 storage vessel 

affected facility, you must achieve the 

required emissions reductions by April 

15, 2014, or within 60 days after startup, 

whichever is later, except as otherwise 

provided below in paragraph (f) of this 

section. For storage vessel affected 

facilities receiving liquids pursuant to 

the standards for gas well affected 

facilities in § 60.5375, you must achieve 

the required emissions reductions 

within 60 days after startup of 

production as defined in § 60.5430. 

* * * * * 

(f) Requirements for Group 1 and 

Group 2 storage vessel affected facilities 

that are removed from service or 

returned to service. If you remove a 

Group 1 or Group 2 storage vessel 

affected facility from service, you must 

comply with paragraphs (f)(1) through 

(3) of this section. A Group 1 or Group 

2 storage vessel is not an affected 

facility under this subpart for the period 

that it is removed from service. 

(1) For a storage vessel affected 

facility to be removed from service, you 

must comply with the requirements of 

paragraph (f)(1)(i) and (ii) of this 

section. 

(i) You must completely empty and 

degas the storage vessel, such that the 

storage vessel no longer contains crude 

oil, condensate, produced water or 

intermediate hydrocarbon liquids. A 

storage vessel where liquid is left on 

walls, as bottom clingage or in pools 

due to floor irregularity is considered to 

be completely empty. 

(ii) You must submit a notification as 

required in § 60.5420(b)(6)(vi) in your 

next annual report, identifying each 

storage vessel affected facility removed 

from service during the reporting period 

and the date of its removal from service. 

(2) If a storage vessel identified in 

paragraph (f)(1)(ii) of this section is 

returned to service, you must determine 

its affected facility status as provided in 

§ 60.5365(e). 

(3) For each storage vessel affected 

facility returned to service during the 

reporting period, you must submit a 

notification in your next annual report 

as required in § 60.5420(b)(6)(vii), 

identifying each storage vessel affected 

facility and the date of its return to 

service. 

* * * * * 

■ 7. Section 60.5401 is amended by 

revising paragraphs (d) and (e) to read 

as follows: 

§ 60.5401 What are the exceptions to the 

equipment leak standards for affected 

facilities at onshore natural gas processing 

plants? 

* * * * * 

(d) Pumps in light liquid service, 

valves in gas/vapor and light liquid 

service, pressure relief devices in gas/

vapor service, and connectors in gas/

vapor service and in light liquid service 

that are located at a nonfractionating 

plant that does not have the design 

capacity to process 283,200 standard 

cubic meters per day (scmd) (10 million 

standard cubic feet per day) or more of 

field gas are exempt from the routine 

monitoring requirements of §§ 60.482– 

2a(a)(1), 60.482–7a(a), 60.482–11a(a), 

and paragraph (b)(1) of this section. 

(e) Pumps in light liquid service, 

valves in gas/vapor and light liquid 

service, pressure relief devices in gas/

vapor service, and connectors in gas/

vapor service and in light liquid service 

within a process unit that is located in 

the Alaskan North Slope are exempt 

from the routine monitoring 

requirements of §§ 60.482–2a(a)(1), 

60.482–7a(a), 60.482–11a(a), and 

paragraph (b)(1) of this section. 

* * * * * 

■ 8. Section 60.5410 is amended by: 

■ a. Revising paragraph (c)(1); 

■ b. Adding a new paragraph (c)(2); and 

■ c. Revising paragraph (d)(2) to read as 

follows: 

§ 60.5410 How do I demonstrate initial 

compliance with the standards for my gas 

well affected facility, my centrifugal 

compressor affected facility, my 

reciprocating compressor affected facility, 

my pneumatic controller affected facility, 

my storage vessel affected facility, and my 

equipment leaks and sweetening unit 

affected facilities at onshore natural gas 

processing plants? 

* * * * * 

(c) * * * 

(1) If complying with § 60.5385(a)(1) 

or (2), during the initial compliance 

period, you must continuously monitor 

the number of hours of operation or 

track the number of months since the 

last rod packing replacement. 

(2) If complying with § 60.5385(a)(3), 

you must operate the rod packing 

emissions collection system under 

negative pressure and route emissions to 

a process through a closed vent system 

that meets the requirements of 

§ 60.5411(a). 

* * * * * 

(d) * * * 

(2) You own or operate a pneumatic 

controller affected facility located at a 

natural gas processing plant and your 

pneumatic controller is driven by a gas 

other than natural gas and therefore 

emits zero natural gas. 

* * * * * 

■ 9. Section 60.5411 is amended by: 

■ a. Revising the section heading and 

introductory text; 

■ b. Revising the heading of paragraph 

(a); 

■ c. Revising paragraph (a)(1); 

■ d. Revising paragraph (b)(3); and 

■ e. Revising the heading of paragraph 

(c). 

The revisions read as follows: 

§ 60.5411 What additional requirements 

must I meet to determine initial compliance 

for my covers and closed vent systems 

routing materials from storage vessels, 

reciprocating compressors and centrifugal 

compressor wet seal degassing systems? 

You must meet the applicable 

requirements of this section for each 

cover and closed vent system used to 

comply with the emission standards for 

your storage vessel, reciprocating 

compressor or centrifugal compressor 

affected facility. 

(a) Closed vent system requirements 

for reciprocating compressors and for 


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centrifugal compressor wet seal 

degassing systems. (1) You must design 

the closed vent system to route all gases, 

vapors, and fumes emitted from the 

material in the reciprocating compressor 

rod packing emissions collection system 

or the wet seal fluid degassing system to 

a control device or to a process that 

meets the requirements specified in 

§ 60.5412(a) through (c). 

* * * * * 

(b) * * * 

(3) Each storage vessel thief hatch 

shall be equipped, maintained and 

operated with a weighted mechanism or 

equivalent, to ensure that the lid 

remains properly seated. You must 

select gasket material for the hatch 

based on composition of the fluid in the 

storage vessel and weather conditions. 

(c) Closed vent system requirements 

for storage vessel affected facilities 

using a control device or routing 

emissions to a process. 

* * * * * 

■ 10. Section 60.5412 is amended by 

revising paragraph (d) introductory text 

to read as follows: 

§ 60.5412 What additional requirements 

must I meet for determining initial 

compliance with control devices used to 

comply with the emission standards for my 

storage vessel or centrifugal compressor 

affected facility? 

* * * * * 

(d) Each control device used to meet 

the emission reduction standard in 

§ 60.5395(d) for your storage vessel 

affected facility must be installed 

according to paragraphs (d)(1) through 

(3) of this section, as applicable. As an 

alternative to paragraph (d)(1) of this 

section, you may install a control device 

model tested under § 60.5413(d), which 

meets the criteria in § 60.5413(d)(11) 

and § 60.5413(e). 

* * * * * 

■ 11. Section 60.5413 is amended by: 

■ a. Revising the introductory text of 

paragraph (e); and 

■ b. Adding paragraph (e)(7). 

The revision and addition read as 

follows: 

§ 60.5413 What are the performance 

testing procedures for control devices used 

to demonstrate compliance at my storage 

vessel or centrifugal compressor affected 

facility? 

* * * * * 

(e) Continuous compliance for 

combustion control devices tested by the 

manufacturer in accordance with 

paragraph (d) of this section. This 

paragraph applies to the demonstration 

of compliance for a combustion control 

device tested under the provisions in 

paragraph (d) of this section. Owners or 

operators must demonstrate that a 

control device achieves the performance 

requirements in (d)(11) of this section 

by installing a device tested under 

paragraph (d) of this section and 

complying with the criteria specified in 

paragraphs (e)(1) through (7) of this 

section. 

* * * * * 

(7) Ensure that each enclosed 

combustion device is maintained in a 

leak free condition. 

■ 12. Section 60.5415 is amended by: 

■ a. Revising paragraph (b)(2) 

introductory text; 

■ b. Revising paragraph (c) introductory 

text; 

■ c. Adding paragraph (c)(4); and 

■ d. Removing paragraph (h). 

The revisions and addition read as 

follows: 

§ 60.5415 How do I demonstrate 

continuous compliance with the standards 

for my gas well affected facility, my 

centrifugal compressor affected facility, my 

stationary reciprocating compressor 

affected facility, my pneumatic controller 

affected facility, my storage vessel affected 

facility, and my affected facilities at onshore 

natural gas processing plants? 

(b) * * * 

(2) For each control device used to 

reduce emissions, you must 

demonstrate continuous compliance 

with the performance requirements of 

§ 60.5412(a) using the procedures 

specified in paragraphs (b)(2)(i) through 

(vii) of this section. If you use a 

condenser as the control device to 

achieve the requirements specified in 

§ 60.5412(a)(2), you must demonstrate 

compliance according to paragraph 

(b)(2)(viii) of this section. You may 

switch between compliance with 

paragraphs (b)(2)(i) through (vii) of this 

section and compliance with paragraph 

(b)(2)(viii) of this section only after at 

least 1 year of operation in compliance 

with the selected approach. You must 

provide notification of such a change in 

the compliance method in the next 

annual report, as required in 

§ 60.5420(b), following the change. 

* * * * * 

(c) For each reciprocating compressor 

affected facility complying with 

§ 60.5385(a)(1) or (2), you must 

demonstrate continuous compliance 

according to paragraphs (c)(1) through 

(3) of this section. For each 

reciprocating compressor affected 

facility complying with § 60.5385(a)(3), 

you must demonstrate continuous 

compliance according to paragraph 

(c)(4) of this section. 

* * * * * 

(4) You must operate the rod packing 

emissions collection system under 

negative pressure and continuously 

comply with the closed vent 

requirements in § 60.5411(a). 

* * * * * 

■ 13. Section 60.5416 is amended by: 

■ a. Revising the section heading; 

■ b. Revising the introductory text; 

■ c. Revising paragraph (a) introductory 

text; and 

■ d. Revising paragraph (b) introductory 

text. 

The revisions read as follows: 

§ 60.5416 What are the initial and 

continuous cover and closed vent system 

inspection and monitoring requirements for 

my storage vessel, centrifugal compressor 

and reciprocating compressor affected 

facilities? 

For each closed vent system or cover 

at your storage vessel, centrifugal 

compressor and reciprocating 

compressor affected facility, you must 

comply with the applicable 

requirements of paragraphs (a) through 

(c) of this section. 

(a) Inspections for closed vent systems 

and covers installed on each centrifugal 

compressor or reciprocating compressor 

affected facility. Except as provided in 

paragraphs (b)(11) and (12) of this 

section, you must inspect each closed 

vent system according to the procedures 

and schedule specified in paragraphs 

(a)(1) and (2) of this section, inspect 

each cover according to the procedures 

and schedule specified in paragraph 

(a)(3) of this section, and inspect each 

bypass device according to the 

procedures of paragraph (a)(4) of this 

section. 

* * * * * 

(b) No detectable emissions test 

methods and procedures. If you are 

required to conduct an inspection of a 

closed vent system or cover at your 

centrifugal compressor or reciprocating 

compressor affected facility as specified 

in paragraphs (a)(1), (2), or (3) of this 

section, you must meet the requirements 

of paragraphs (b)(1) through (13) of this 

section. 

* * * * * 

■ 14. Section 60.5420 is amended by: 

■ a. Revising paragraph (b)(1)(iv); 

■ b. Revising paragraph (b)(6)(ii); 

■ c. Revising paragraphs (b)(6)(vi) and 

(vii); 

■ d. Revising paragraphs (c)(1)(iii)(A) 

and (B); 

■ e. Revising paragraph (c)(3)(ii); and 

■ f. Revising paragraphs (c)(7), (8) and 

(9). 

The revisions read as follows: 

§ 60.5420 What are my notification, 

reporting, and recordkeeping 

requirements? 

* * * * * 


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(b) * * * 

(1) * * * 

(iv) A certification by a certifying 

official of truth, accuracy, and 

completeness. This certification shall 

state that, based on information and 

belief formed after reasonable inquiry, 

the statements and information in the 

document are true, accurate, and 

complete. 

* * * * * 

(6) * * * 

(ii) Documentation of the VOC 

emission rate determination according 

to § 60.5365(e) for each storage vessel 

that became an affected facility during 

the reporting period or is returned to 

service during the reporting period. 

* * * * * 

(vi) You must identify each storage 

vessel affected facility that is removed 

from service during the reporting period 

as specified in § 60.5395(f)(1)(ii), 

including the date the storage vessel 

affected facility was removed from 

service. 

(vii) You must identify each storage 

vessel affected facility returned to 

service during the reporting period as 

specified in § 60.5395(f)(3), including 

the date the storage vessel affected 

facility was returned to service. 

* * * * * 

(c) * * * 

(1) * * * 

(iii) * * * 

(A) For each gas well affected facility 

required to comply with the 

requirements of § 60.5375(a), you must 

record: The location of the well; the API 

well number; the date and time of the 

onset of flowback following hydraulic 

fracturing or refracturing; the date and 

time of each attempt to direct flowback 

to a separator as required in 

§ 60.5375(a)(1)(i); the date and time of 

each occurrence of returning to the 

initial flowback stage under 

§ 60.5375(a)(1)(i); and the date and time 

that the well was shut in and the 

flowback equipment was permanently 

disconnected, or the startup of 

production; the duration of flowback; 

duration of recovery to the flow line; 

duration of combustion; duration of 

venting; and specific reasons for venting 

in lieu of capture or combustion. The 

duration must be specified in hours of 

time. 

(B) For each gas well affected facility 

required to comply with the 

requirements of § 60.5375(f), you must 

maintain the records specified in 

paragraph (c)(1)(iii)(A) of this section 

except that you do not have to record 

the duration of recovery to the flow line. 

* * * * * 

(3) * * * 

(ii) Records of the date and time of 

each reciprocating compressor rod 

packing replacement, or date of 

installation of a rod packing emissions 

collection system and closed vent 

system as specified in § 60.5385(a)(3). 

* * * * * 

(7) A record of each cover inspection 

required under § 60.5416(a)(3) for 

centrifugal or reciprocating compressors 

or § 60.5416(c)(2) for storage vessels. 

(8) If you are subject to the bypass 

requirements of § 60.5416(a)(4) for 

centrifugal or reciprocating compressors 

or § 60.5416(c)(3) for storage vessels, a 

record of each inspection or a record 

each time the key is checked out or a 

record of each time the alarm is 

sounded. 

(9) If you are subject to the closed 

vent system no detectable emissions 

requirements of § 60.5416(b) for 

centrifugal or reciprocating 

compressors, a record of the monitoring 

conducted in accordance with 

§ 60.5416(b). 

* * * * * 

■ 15. Section 60.5430 is amended by: 

■ a. Adding, in alphabetical order, 

definitions for the terms ‘‘Certifying 

official,’’ ‘‘Collection system,’’ ‘‘Initial 

flowback stage,’’ ‘‘Maximum average 

daily throughput,’’ ‘‘Recovered gas,’’ 

‘‘Recovered liquids,’’ ‘‘Removed from 

service,’’ ‘‘Returned to service,’’ 

‘‘Separation flowback stage,’’ ‘‘Startup 

of production,’’ and ‘‘Well completion 

vessel;’’ 

■ b. Removing the definition of 

‘‘Affirmative defense;’’ and 

■ c. Revising the definitions for 

‘‘Equipment’’, ‘‘Flowback,’’ ‘‘Routed to a 

process or route to a process,’’ ‘‘Salable 

quality gas,’’ and ‘‘Storage vessel.’’ 

The revisions read as follows: 

§ 60.5430 What definitions apply to this 

subpart? 

* * * * * 

Certifying official means one of the 

following: 

(1) For a corporation: A president, 

secretary, treasurer, or vice-president of 

the corporation in charge of a principal 

business function, or any other person 

who performs similar policy or 

decision-making functions for the 

corporation, or a duly authorized 

representative of such person if the 

representative is responsible for the 

overall operation of one or more 

manufacturing, production, or operating 

facilities applying for or subject to a 

permit and either: 

(i) The facilities employ more than 

250 persons or have gross annual sales 

or expenditures exceeding $25 million 

(in second quarter 1980 dollars); or 

(ii) The Administrator is notified of 

such delegation of authority prior to the 

exercise of that authority. The 

Administrator reserves the right to 

evaluate such delegation; 

(2) For a partnership (including but 

not limited to general partnerships, 

limited partnerships, and limited 

liability partnerships) or sole 

proprietorship: A general partner or the 

proprietor, respectively. If a general 

partner is a corporation, the provisions 

of paragraph (1) of this definition apply; 

(3) For a municipality, State, Federal, 

or other public agency: Either a 

principal executive officer or ranking 

elected official. For the purposes of this 

part, a principal executive officer of a 

Federal agency includes the chief 

executive officer having responsibility 

for the overall operations of a principal 

geographic unit of the agency (e.g., a 

Regional Administrator of EPA); or 

(4) For affected facilities: 

(i) The designated representative in so 

far as actions, standards, requirements, 

or prohibitions under title IV of the 

Clean Air Act or the regulations 

promulgated thereunder are concerned; 

or 

(ii) The designated representative for 

any other purposes under part 60. 

* * * * * 

Collection system means any 

infrastructure that conveys gas or 

liquids from the well site to another 

location for treatment, storage, 

processing, recycling, disposal or other 

handling. 

* * * * * 

Equipment, as used in the standards 

and requirements in this subpart 

relative to the equipment leaks of VOC 

from onshore natural gas processing 

plants, means each pump, pressure 

relief device, open-ended valve or line, 

valve, and flange or other connector that 

is in VOC service or in wet gas service, 

and any device or system required by 

those same standards and requirements 

in this subpart. 

* * * * * 

Flowback means the process of 

allowing fluids and entrained solids to 

flow from a natural gas well following 

a treatment, either in preparation for a 

subsequent phase of treatment or in 

preparation for cleanup and returning 

the well to production. The term 

flowback also means the fluids and 

entrained solids that emerge from a 

natural gas well during the flowback 

process. The flowback period begins 

when material introduced into the well 

during the treatment returns to the 

surface following hydraulic fracturing or 

refracturing. The flowback period ends 

when either the well is shut in and 


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Federal Register / Vol. 79, No. 250 / Wednesday, December 31, 2014 / Rules and Regulations 79041 

permanently disconnected from the 

flowback equipment or at the startup of 

production. The flowback period 

includes the initial flowback stage and 

the separation flowback stage. 

* * * * * 

Initial flowback stage means the 

period during a well completion 

operation which begins at the onset of 

flowback and ends at the separation 

flowback stage. 

* * * * * 

Maximum average daily throughput 

means the earliest calculation of daily 

average throughput during the 30-day 

PTE evaluation period employing 

generally accepted methods. 

* * * * * 

Recovered gas means gas recovered 

through the separation process during 

flowback. 

Recovered liquids means any crude 

oil, condensate or produced water 

recovered through the separation 

process during flowback. 

* * * * * 

Removed from service means that a 

storage vessel affected facility has been 

physically isolated and disconnected 

from the process for a purpose other 

than maintenance in accordance with 

§ 60.5395(f)(1). 

Returned to service means that a 

Group 1 or Group 2 storage vessel 

affected facility that was removed from 

service has been: 

(1) Reconnected to the original source 

of liquids, connected in parallel to any 

storage vessel affected facility or has 

been used to replace any storage vessel 

affected facility; or 

(2) Installed in any location covered 

by this subpart and introduced with 

crude oil, condensate, intermediate 

hydrocarbon liquids or produced water. 

Routed to a process or route to a 

process means the emissions are 

conveyed via a closed vent system to 

any enclosed portion of a process 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. 

Salable quality gas means natural gas 

that meets the flow line or collection 

system operator specifications, 

regardless of whether such gas is sold. 

Separation flowback stage means the 

period during a well completion 

operation when it is technically feasible 

for a separator to function. The 

separation flowback stage ends either at 

the startup of production, or when the 

well is shut in and permanently 

disconnected from the flowback 

equipment. 

Startup of production means the 

beginning of initial flow following the 

end of flowback when there is 

continuous recovery of salable quality 

gas and separation and recovery of any 

crude oil, condensate or produced 

water. 

Storage vessel means a tank or other 

vessel that contains an accumulation of 

crude oil, condensate, intermediate 

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. Two 

or more storage vessels connected in 

parallel are considered equivalent to a 

single storage vessel with throughput 

equal to the total throughput of the 

storage vessels connected in parallel. A 

well completion vessel that receives 

recovered liquids from a well after 

startup of production following 

flowback for a period which exceeds 60 

days is considered a storage vessel 

under this subpart. A tank or other 

vessel shall not be considered a storage 

vessel if it has been removed from 

service in accordance with the 

requirements of § 60.5395(f) until such 

time as such tank or other vessel has 

been returned to service. For the 

purposes of this subpart, the following 

are not considered storage vessels: 

(1) Vessels that are skid-mounted or 

permanently attached to something that 

is mobile (such as trucks, railcars, 

barges or ships), and are intended to be 

located at a site for less than 180 

consecutive days. If you do not keep or 

are not able to produce records, as 

required by § 60.5420(c)(5)(iv), showing 

that the vessel has been located at a site 

for less than 180 consecutive days, the 

vessel described herein is considered to 

be a storage vessel from the date the 

original vessel was first located at the 

site. This exclusion does not apply to a 

well completion vessel as described 

above. 

(2) Process vessels such as surge 

control vessels, bottoms receivers or 

knockout vessels. 

(3) Pressure vessels designed to 

operate in excess of 204.9 kilopascals 

and without emissions to the 

atmosphere. 

* * * * * 

Well completion vessel means a vessel 

that contains flowback during a well 

completion operation following 

hydraulic fracturing or refracturing. A 

well completion vessel may be a lined 

earthen pit, a tank or other vessel that 

is skid-mounted or portable. A well 

completion vessel that receives 

recovered liquids from a well after 

startup of production following 

flowback for a period which exceeds 60 

days is considered a storage vessel 

under this subpart. 

* * * * * 

[FR Doc. 2014–30630 Filed 12–30–14; 8:45 am] 

BILLING CODE 6560–50–P 


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