Vol. 78 Friday, 

No. 71 April 12, 2013 

Part IV 

Environmental Protection Agency 

40 CFR Part 60 

Oil and Natural Gas Sector: Reconsideration of Certain Provisions of New 

Source Performance Standards; Proposed Rule 

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22126 Federal Register / Vol. 78, No. 71 / Friday, April 12, 2013 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 60 

[EPA–HQ–OAR–2010–0505, FRL–9791–9] 

RIN 2060–AR75 

Oil and Natural Gas Sector: 

Reconsideration of Certain Provisions 

of New Source Performance Standards 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule; notice of public 

hearing. 

SUMMARY: On August 16, 2012, the EPA 

published final new source performance 

standards for the oil and natural gas 

sector. The Administrator received 

petitions for reconsideration of certain 

aspects of the standards. In this notice, 

the EPA is announcing proposed 

amendments as a result of 

reconsideration of certain issues related 

to implementation of storage vessel 

provisions. The proposed amendments 

also correct technical errors that were 

inadvertently included in the final rule. 

DATES: Comments. Comments must be 

received on or before May 13, 2013, 

unless a public hearing is requested by 

April 17, 2013. If a hearing is requested 

on this proposed rule, written 

comments must be received by May 28, 

2013. 

Public Hearing. If anyone contacts the 

EPA requesting a public hearing by 

April 17, 2013 we will hold a public 

hearing on April 29, 2013. 

Public Hearing. If a public hearing is 

requested by April 17, 2013, it will be 

held on April 29, 2013 at the EPA’s 

Research Triangle Park Campus, 109 

T.W. Alexander Drive, Research 

Triangle Park, NC 27711. The hearing 

will convene at 10:00 a.m. (Eastern 

Standard Time) and end at 5:00 p.m. 

(Eastern Standard Time). A lunch break 

will be held from 12:00 p.m. (Eastern 

Standard Time) until 1:00 p.m. (Eastern 

Standard Time). Please contact Joan C. 

Rogers at (919) 541–4487, or at 

rogers.joanc@epa.gov to request a 

hearing, to determine if a hearing will 

be held and to register to speak at the 

hearing, if one is held. If a hearing is 

requested, the last day to pre-register in 

advance to speak at the hearing will be 

April 25, 2013. Additionally, requests to 

speak will be taken the day of the 

hearing at the hearing registration desk, 

although preferences on speaking times 

may not be able to be fulfilled. If you 

require the service of a translator or 

special accommodations such as audio 

description, please let us know at the 

time of registration. If no one contacts 

the EPA requesting a public hearing to 

be held concerning this proposed rule 

by April 17, 2013, a public hearing will 

not take place. 

If a hearing is held, it will provide 

interested parties the opportunity to 

present data, views or arguments 

concerning the proposed action. The 

EPA will make every effort to 

accommodate all speakers who arrive 

and register. Because this hearing, if 

held, will be at a U.S. governmental 

facility, individuals planning to attend 

the hearing should be prepared to show 

valid picture identification to the 

security staff in order to gain access to 

the meeting room. In addition, you will 

need to obtain a property pass for any 

personal belongings you bring with you. 

Upon leaving the building, you will be 

required to return this property pass to 

the security desk. No large signs will be 

allowed in the building, cameras may 

only be used outside of the building and 

demonstrations will not be allowed on 

federal property for security reasons. 

The EPA may ask clarifying questions 

during the oral presentations but will 

not respond to the presentations at that 

time. Written statements and supporting 

information submitted during the 

comment period will be considered 

with the same weight as oral comments 

and supporting information presented at 

the public hearing. If a hearing is held 

on April 29, 2013, written comments on 

the proposed rule must be postmarked 

by May 28, 2013. Commenters should 

notify Ms. Rogers if they will need 

specific equipment, or if there are other 

special needs related to providing 

comments at the hearing. The EPA will 

provide equipment for commenters to 

show overhead slides or make 

computerized slide presentations if we 

receive special requests in advance. Oral 

testimony will be limited to 5 minutes 

for each commenter. The EPA 

encourages commenters to provide the 

EPA with a copy of their oral testimony 

electronically (via email or CD) or in 

hard copy form. Verbatim transcripts of 

the hearings and written statements will 

be included in the docket for the 

rulemaking. The EPA will make every 

effort to follow the schedule as closely 

as possible on the day of the hearing; 

however, please plan for the hearing to 

run either ahead of schedule or behind 

schedule. Information regarding the 

hearing (including information as to 

whether or not one will be held) will be 

available at: http://www.epa.gov/ 

airquality/oilandgas/actions.html. 

Again, all requests for a public hearing 

to be held must be received by April 17, 

2013. 

ADDRESSES: Submit your comments, 

identified by Docket ID Number EPA– 

HQ–OAR–2010–0505, by one of the 

following methods: 

• http://www.regulations.gov. Follow 

the online instructions for submitting 

comments. 

• Email: Comments may be sent by 

electronic mail (email) to a-and-rdocket@epa.gov, Attention Docket ID 

Number EPA–HQ–OAR–2010–0505. 

• Fax: Fax your comments to: (202) 

566–1741, Attention Docket ID Number 

EPA–HQ–OAR–2010–0505. 

• Mail: Send your comments on this 

action to: EPA Docket Center (EPA/DC), 

Environmental Protection Agency, 

Mailcode: 2822T, 1200 Pennsylvania 

Ave. NW., Washington, DC 20460, 

Docket ID Number EPA–HQ–OAR– 

2010–0505. Please include a total of two 

copies. The EPA requests a separate 

copy also be sent to the contact person 

identified below (see FOR FURTHER

INFORMATION CONTACT). 

• Hand Delivery or Courier: Deliver 

your comments to: EPA Docket Center, 

EPA West, Room 3334, 1301 

Constitution Ave. NW., Washington, DC 

20460. Please include a total of two 

copies. Such deliveries are only 

accepted during the Docket’s normal 

hours of operation (8:30 a.m. to 4:30 

p.m., Monday through Friday, excluding 

legal holidays), and special 

arrangements should be made for 

deliveries of boxed information. 

Instructions: All submissions must 

include agency name and respective 

docket number or Regulatory 

Information Number (RIN) for this 

rulemaking. All comments will be 

posted without change and may be 

made available online at http:// 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be confidential business 

information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through http:// 

www.regulations.gov or email. The 

http://www.regulations.gov Web site is 

an ‘‘anonymous access’’ system, which 

means the EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you send an email 

comment directly to the EPA without 

going through http:// 

www.regulations.gov, your email 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, the EPA 

recommends that you include your 

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Federal Register / Vol. 78, No. 71 / Friday, April 12, 2013 / Proposed Rules 22127 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If the EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, the EPA may not 

be able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption and be free of any defects or 

viruses. 

Docket: 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., CBI or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

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 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) 541–3470; 

email address: moore.bruce@epa.gov. 

SUPPLEMENTARY INFORMATION: Outline. 

The information presented in this 

preamble is organized as follows: 

I. Preamble Acronyms and Abbreviations 

II. General Information 

A. Does this reconsideration notice apply 

to me? 

B. What should I consider as I prepare my 

comments to the EPA? 

C. How do I obtain a copy of this document 

and other related information? 

III. Background 

IV. Today’s Action 

V. Executive Summary 

VI. Discussion of Provisions Subject to 

Reconsideration 

A. Storage Vessels Implementation 

B. Periodic Monitoring and Testing of 

Closed-Vent Systems and Control 

Devices 

C. Test Protocol for Combustion Control 

Devices 

D. Annual Report and Compliance 

Certification 

E. Properly Designed Storage Vessels, 

Closed-Vent Systems and Control 

Devices 

VII. Technical Corrections and Clarifications 

VIII. Impacts of This Proposed Rule 

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 proposed 

standards? 

IX. 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 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act of 1995 

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 

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 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

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: 

API American Petroleum Institute 

BOE Barrels of Oil Equivalent 

bbl Barrel 

bpd Barrels Per Day 

BID Background Information Document 

BSER Best System of Emissions Reduction 

CAA Clean Air Act 

CFR Code of Federal Regulations 

CPMS Continuous Parametric Monitoring 

Systems 

EIA Energy Information Administration 

EPA Environmental Protection Agency 

GOR Gas to Oil Ratio 

HAP Hazardous Air Pollutant 

HPDI HPDI, LLC 

Mcf Thousand Cubic Feet 

NTTAA National Technology Transfer and 

Advancement Act of 1995 

NEI National Emissions Inventory 

NEMS National Energy Modeling System 

NESHAP National Emissions Standards for 

Hazardous Air Pollutants 

NSPS New Source Performance Standards 

OAQPS Office of Air Quality Planning and 

Standards 

OMB Office of Management and Budget 

OVA Olfactory, Visual and Auditory 

PRA Paperwork Reduction Act 

PTE Potential to Emit 

RFA Regulatory Flexibility Act 

SISNOSE Significant Economic Impact on a 

Substantial Number of Small Entities 

tpy Tons per Year 

TTN Technology Transfer Network 

UMRA Unfunded Mandates Reform Act 

VCS Voluntary Consensus Standards 

VOC Volatile Organic Compounds 

VRU Vapor Recovery Unit 

II. General Information 

A. Does this reconsideration notice 

apply to me? 

Categories and entities potentially 

affected by today’s notice 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 or 40 CFR 63.13 

(General Provisions). 

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B. What should I consider as I prepare 

my comments to the EPA? 

We seek comment only on the aspects 

of the final new source performance 

standards for the oil and natural gas 

sector specifically identified in this 

notice. We are not opening for 

reconsideration any other provisions of 

the new source performance standards 

at this time. 

Do not submit information containing 

CBI to the EPA through http:// 

www.regulations.gov or email. Send or 

deliver information identified as CBI 

only to the following address: Roberto 

Morales, OAQPS Document Control 

Officer (C404–02), Office of Air Quality 

Planning and Standards, U.S. 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711, Attention: Docket ID Number 

EPA–HQ–OAR–2010–0505. Clearly 

mark the part or all of the information 

that you claim to be CBI. For CBI 

information in a disk or CD–ROM that 

you mail to the EPA, mark the outside 

of the disk or CD–ROM as CBI and then 

identify electronically within the disk or 

CD–ROM the specific information that 

is claimed as CBI. In addition to one 

complete version of the comment that 

includes information claimed as CBI, a 

copy of the comment that does not 

contain the information claimed as CBI 

must be submitted for inclusion in the 

public docket. Information so marked 

will not be disclosed except in 

accordance with procedures set forth in 

40 CFR part 2. 

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 these 

proposed rules will be available on the 

Worldwide Web through the TTN. 

Following signature, a copy of each 

proposed rule will be posted on the 

TTN’s policy and guidance page for 

newly proposed or promulgated rules at 

the following address: http:// 

www.epa.gov/ttn/oarpg/. The TTN 

provides information and technology 

exchange in various areas of air 

pollution control. 

III. Background 

The Administrator signed the Oil and 

Natural Gas Sector NSPS (40 CFR part 

60 subpart OOOO) on April 17, 2012, 

and the final rule was published in the 

Federal Register at 77 FR 49490, August 

16, 2012. Following promulgation of the 

final rule, the Administrator received 

petitions for reconsideration of several 

provisions of the NSPS pursuant to CAA 

section 307(d)(7)(B). Copies of the 

petitions are provided in rulemaking 

docket EPA–HQ–OAR–2010–0505. 

IV. Today’s Action 

Today, we are granting 

reconsideration of, proposing and 

requesting comment on the following 

limited set of issues raised in the 

petitions described above: (1) 

Implementation date for the storage 

vessel provisions; (2) definition of 

‘‘storage vessel’’; (3) definition of 

‘‘storage vessel affected facility’’ for 

applicability purposes; (4) requirements 

for storage vessels constructed, modified 

or reconstructed during the period from 

the NSPS proposal date, August 23, 

2011, to April 12, 2013; (5) an 

alternative mass-based standard for 

storage vessels after extended periods of 

low uncontrolled emissions; (6) 

compliance demonstration and 

monitoring provisions for closed-vent 

systems and control devices for storage 

vessels; (7) revised and clarified 

protocol for manufacturer testing of 

enclosed combustors; (8) broadening of 

the provision for determining VOC 

emissions and installing controls from 

only those affected storage vessels in 

certain locations to all affected storage 

vessels regardless of location; and (9) 

time period allowed for submittal of 

annual reports and compliance 

certifications. Finally, we are proposing 

to correct technical errors that were 

inadvertently included in the final rule. 

This notice is limited to the specific 

issues identified in this notice. We will 

not respond to any comments 

addressing any other provisions of the 

oil and natural gas sector NSPS. We will 

address other issues for which we 

intend to grant reconsideration at a later 

time. 

The impacts of today’s proposed 

revisions on the costs and the benefits 

of the final rule are minor but costsaving. We expect that affected facility 

owners and operators will install and 

operate the same or similar control 

technologies to meet the proposed 

revised standards in this notice as they 

would have chosen to comply with the 

standards in the August 2012 final rule, 

and revisions to the rule will not 

significantly increase emissions. 

V. Executive Summary 

The purpose of this action is to 

propose amendments to 40 CFR part 60, 

subpart OOOO, Standards of 

Performance for Crude Oil and Natural 

Gas Production, Transmission and 

Distribution. This proposal was 

developed to address certain issues 

primarily related to implementation of 

storage vessel provisions that have been 

raised by different stakeholders through 

several administrative petitions for 

reconsideration of the 2012 NSPS. The 

EPA is proposing to amend the NSPS to 

address these issues. 

Information the EPA had during 

development of the final rule led to 

underestimation of the number of 

affected storage vessels. In response to 

information presented in some of the 

petitions for reconsideration, we have 

revised the estimated number of storage 

vessels subject to, and impacted by, the 

final NSPS. Based on the increased 

number of storage vessels we now 

estimate will be impacted by the 

proposed rule, it is clear that more time 

will be needed for a sufficient number 

of control devices to become available 

for the impacted storage vessels. 

Based on our analysis and the 

information provided to us, we believe 

that there are on the order of 970 storage 

vessels per month being installed at this 

time and expected in the future, and 

over 20,000 affected storage vessels 

constructed, modified or reconstructed 

between the August 23, 2011, proposal 

date of the NSPS and April 12, 2013. 

For ease of reference in this notice, we 

refer to affected storage vessels 

constructed, modified or reconstructed 

between the August 23, 2011, proposal 

date of the NSPS and April 12, 2013 as 

‘‘Group 1’’ and the cohort of storage 

vessels constructed, modified or 

reconstructed after April 12, 2013 as 

‘‘Group 2.’’ Further, based on 

information available to us, there will 

not be a sufficient supply of control 

devices until 2016. To avoid postponing 

control for all affected storage vessels 

until 2016, we are proposing alternative 

measures for Group 1 affected sources, 

because many of these sources will 

likely have experienced significant 

emissions decline during this period. 

For Group 2 affected sources, we are 

proposing an April 15, 2014, 

compliance date for implementing the 

control requirements. For Group 1, 

instead of installation of a control 

device by April 15, 2014, we are 

proposing to require initial notification 

by October 15, 2013, to inform 

regulatory agencies of the existence and 

location of the vessels. We are also 

proposing that affected storage vessels 

in Group 1 that undergo an event after 

April 12, 2013 that leads to an increase 

in emissions, even without a physical 

change or change in the method of 

operation, implement the same control 

requirements as Group 2. 

For storage vessels that have installed 

controls to meet the 95 percent VOC 

reduction standard, we are proposing 

streamlined compliance monitoring 

provisions that would be in place 

during our reconsideration of certain 

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issues raised in the reconsideration 

petitions relative to the current 

compliance demonstration and 

monitoring requirements. We are 

proposing these streamlined provisions 

to provide assurance of compliance 

during the reconsideration period, while 

allowing the EPA time to consider fully 

the issues raised by petitioners 

concerning initial and continuous 

compliance provisions of the final 

NSPS. These compliance monitoring 

provisions include inspections 

performed at least monthly of covers, 

closed-vent systems and control 

devices. These procedures were selected 

to provide frequent checks that will lead 

to prompt repairs, to be performed by 

personnel already at the site and would 

require little or no specialized 

compliance monitoring training or 

equipment. 

We are also proposing that the storage 

vessel standards include a sustained 

uncontrolled VOC emission rate of less 

than 4 tpy as an alternative emission 

limit to the 95 percent control in the 

final NSPS under specified 

circumstances. Specifically, the 

proposed alternative emission limit 

would be available to those who can 

demonstrate, based on records for the 12 

months immediately preceding the 

demonstration and while the control is 

on, that its uncontrolled emissions 

during that 12 month-period would 

have been below 4 tpy. More detailed 

discussion of the less than 4 tpy 

emission limit is presented in section 

VI.A.4. We believe this alternate 

standard reflects the decline in 

production that all wells experience 

over time and allows control devices to 

be reused at other locations, which 

would help alleviate control device 

supply shortages. If, however, emissions 

subsequently increase above the 4 tpy 

limit, the sources would need to comply 

with the 95 percent control requirement 

as discussed in detail in section VI.4. 

We are proposing to amend the 

definition of ‘‘storage vessel’’ to clarify 

that it refers only to vessels containing 

crude oil, condensate, intermediate 

hydrocarbon liquids or produced water. 

We believe this amendment addresses 

concerns raised by several petitioners 

that the definition in the final NSPS was 

overly broad and encompassed a 

number of unintended vessels, such as 

fuel tanks. 

We are also proposing to amend the 

definition of ‘‘storage vessel affected 

facility’’ to include the 6 tpy VOC 

emission threshold. Without this 

threshold, the affected facility definition 

could impose unnecessary burden on 

operators of storage vessels that are not 

required to reduce emissions. In 

addition, we are proposing to clarify 

that a source can take into account any 

legal and practically enforceable 

emission limit under federal, state or 

local authority when determining the 

VOC emission rate for purposes of this 

threshold (i.e., they would not be 

subject to the storage vessel provisions 

of the NSPS if their potential to emit 

VOC was required to be less than 6 tpy 

under such limitation and in fact was). 

We are proposing to revise the 

combustor control device manufacturer 

test protocol in the NSPS to align it with 

a similar protocol in the Oil and Natural 

Gas NESHAP (40 CFR 63, subpart HH). 

Our intent in the final NSPS was to 

make the NSPS and NESHAP protocols 

consistent. In addition, we are soliciting 

comment on a potential compliance 

approach based on the use of these 

manufacturer-tested combustor models. 

This potential compliance approach 

takes advantage of an opportunity to 

reduce the compliance burden on the 

affected facility. A discussion of this 

concept as it relates to this rule is 

presented in section VI.C of this 

preamble. 

We are proposing to clarify that a 

storage vessel affected facility whose 

VOC emissions decrease to less than the 

threshold of 6 tpy would remain an 

affected facility. We believe this 

amendment is necessary to clarify that 

a storage vessel complying with the 

proposed alternative emission limit of 

less than 4 tpy would remain an affected 

facility and would be required to meet 

the 95 percent reduction standard 

should its uncontrolled emissions 

increase to 4 tpy or above in the future. 

The final NSPS requires the annual 

report and compliance certification to 

be submitted within 30 days after the 

end of the compliance period. Several 

petitioners stated that because the 

annual report requires signature by a 

responsible official to certify the truth, 

accuracy and completeness of the 

report, 30 days is insufficient to compile 

all the required information and to 

obtain the signature of a senior company 

official. Therefore, we are proposing to 

allow 90 days after the end of the 

compliance period for submittal of the 

annual report and compliance 

certification. We are also proposing to 

make several clarifications and 

technical edits to the final NSPS. 

In addition to the proposed revisions 

to the requirements discussed above, we 

present a discussion in section VI.E 

concerning the importance of proper 

design, sizing and operation of storage 

vessel affected facilities, their closedvent systems and associated control 

devices. Improper design or operation of 

a storage vessel and its control system 

can result in occurrences where peak 

flow overwhelms the storage vessel and 

its capture systems, resulting in 

emissions that do not reach the control 

device. 

VI. Discussion of Provisions Subject to 

Reconsideration 

As summarized above, the EPA is 

proposing to address a number of issues 

that have been raised by different 

stakeholders through several 

administrative petitions for 

reconsideration of the final NSPS. The 

following sections present the issues 

raised by the petitioners that the EPA is 

addressing in this action and how the 

EPA proposes to resolve the issues. We 

also provide below a discussion of the 

EPA’s expectations that operators will 

employ proper design, sizing and 

operation of storage vessel affected 

facilities, their closed-vent systems and 

their associated control devices. 

A. Storage Vessels Implementation 

1. Emission Standards for Storage 

Vessels 

In their petitions for reconsideration, 

two petitioners stated that the EPA had 

significantly underestimated the 

number of storage vessels subject to and 

impacted by the NSPS. The petitioners 

pointed out that the EPA had based its 

analysis to predict the number of storage 

vessels that would be subject to and 

impacted by the final rules on storage 

vessels that were located at existing low 

producing wells. They reasoned that 

storage vessels at low producing wells 

were likely to have low throughput with 

corresponding low rates of flash 

emissions. Petitioners asserted that they 

estimated the number of affected storage 

vessels to be approximately 28,000 per 

year. They stated that, because their 

estimate was much higher than the 304 

storage vessels per year the EPA had 

estimated, the 1-year phase in for the 

storage vessel requirements provided in 

the final rule was insufficient time for 

an adequate number of control devices 

to become available to meet demand. 

The petitioners suggested remedies that 

could help alleviate the shortage of 

control devices necessary to control the 

much greater number of storage vessels 

than the EPA had estimated: (1) Provide 

a greater period of time for phase in (i.e., 

3 years instead of the 1 year provided 

in the final rule); and (2) allow removal 

of control devices after an extended 

period of low uncontrolled emissions. 

The first suggestion is addressed below 

in this section; the second is addressed 

in section VI.A.4. 

In light of petitioners’ assertions, we 

revisited our estimate of the number of 

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22130 Federal Register / Vol. 78, No. 71 / Friday, April 12, 2013 / Proposed Rules 

storage vessels subject to the final NSPS. 

Our existing estimate was based on 

information reported in the NEI that had 

been used to develop the storage vessels 

provisions of NESHAP subpart HH 

several years ago. These data, combined 

with model plant information and 

modeled using over 100 tank datasets 

provided as part of API E&P TANKS, 

were used to develop an estimate of 

storage vessels expected to have VOC 

emissions of at least 6 tpy, the 

applicability threshold for storage 

vessels in the NSPS final rule. 

In our original estimate, we used the 

throughput distribution of crude oil and 

condensate storage vessels as reported 

in the BID for NESHAP subpart HH to 

estimate the number of storage vessels 

in each of several throughput categories. 

This distribution was important because 

it was directly related to how we 

estimated VOC emissions from the 

tanks. We now know that the BID data 

were highly biased towards lower 

throughput tanks, which typically have 

lower emissions. We realize that, 

because of the high production rates of 

hydraulically fractured wells (the 

predominant type of wells today and 

expected to be the predominant type of 

wells in the future), the liquid 

throughput and resulting flash 

emissions for future storage vessels are 

much higher than for the storage vessels 

represented by the BID data. Thus, we 

now realize that the vast majority of the 

tanks, according to the BID distribution, 

were lower throughput tanks with VOC 

emissions less than 6 tpy, while a much 

higher number of future storage vessels 

are expected to have emissions of 6 tpy 

or more. Further, we now realize that 

historical trends we have used in the 

past to project industry growth are not 

applicable to the oil and natural gas 

sector going forward. This also 

contributed to our underestimate of 

affected storage vessels in the final rule 

analysis. In summary, the much higher 

production wells and correspondingly 

higher storage vessel emissions, 

combined with the great increase in the 

number of wells and associated storage 

vessels, resulted in the number of 

affected storage vessels to be greatly 

underestimated. 

Based on the information from the 

petitioners, our re-evaluation of our 

dataset, and additional information 

described below, we revised our 

estimate of the number of storage 

vessels subject to the final NSPS. We 

estimated the number of new storage 

vessels predicted to be installed by 

assuming that there would be one 

storage vessel associated with each 

completed well. We understand that 

there may be more than one storage 

vessel associated with each well, but 

because the majority of VOC emissions 

from storage vessels occur due to 

flashing from the first storage vessel 

after the separator (where the pressure 

differential between devices is the 

greatest), other storage vessels would 

have comparatively lower emissions. 

Further, if more than one storage vessel 

does exist at the well site, it is likely 

that owners and operators would 

manifold these storage vessels together 

and route them to a single control 

device or VRU. 

We recognize that an additional 

source of uncertainty in our revised 

analysis is that we are not able to 

estimate the number of wells on multiwell pads. We believe that these multiwell pads would be more likely to take 

advantage of the proximity of available 

storage vessel capacity, resulting in 

more than one well being associated 

with a storage vessel or group of storage 

vessels. 

For the reasons stated above, we 

believe that our assumption of one 

storage vessel per well provides a 

reasonable basis for estimating the 

number of affected storage vessels since 

August 23, 2011, (the date the NSPS was 

proposed) and for future years. We drew 

estimates and predictions of the number 

of completed wells from 2011 to 2015 

from the EIA NEMS 2012 forecasting 

model, a modeling platform consistent 

with the 2012 Annual Energy Outlook 

reference case. 

To estimate the number of storage 

vessels that would be associated with 

wells of various production ranges, we 

used well-level production information 

from 2009 contained in the HPDI 

database to distribute the predicted 

number of well completions across a 

range of production rate categories using 

the same proportions as the 2009 well 

completion data. 

We also made an effort to account for 

the number of storage vessels that 

would already be subject to and 

controlled under state environmental 

regulations. We analyzed the regulations 

in the 11 states that represented 95 

percent of the total production of crude 

oil and condensate in the U.S. 

(according to production information 

published by the EIA). These states were 

Alaska, California, Colorado, Kansas, 

Louisiana, Montana, North Dakota, New 

Mexico, Oklahoma, Texas and 

Wyoming. These storage vessels were 

then subtracted from the overall count 

of storage vessels that would be subject 

to the final rule. 

As a result, we estimated that there 

may be as many as 46,000 new 

condensate and crude oil storage vessels 

installed that would be subject to the 

NSPS from August 23, 2011 (the date 

upon which new, modified or 

reconstructed storage vessels become 

affected facilities under the NSPS), until 

October 15, 2015. This is an average of 

approximately 11,600 storage vessels 

per year, or about 970 per month. By the 

current compliance date of October 15, 

2013, over 20,000 storage vessels will 

have come online since the original 

proposal date. These units will need to 

be controlled by October 15, 2013, 

under the current final NSPS. 

Based on our reanalysis, we have 

reason to believe that there was already 

significant demand for storage vessel 

emissions control devices prior to the 

2012 NSPS. For example, as discussed 

above, several states require operators to 

control VOC emissions from storage 

vessels. The EPA received information 

from the oil and natural gas industry 

indicating that 3,680 control devices 

could be manufactured per year as of 

2012, or about 300 per month. We 

assumed that, since the NSPS 

requirements were not yet finalized 

when the agency received this 

information, most of this supply of 

equipment was being purchased by 

operators needing to meet state 

requirements. The 300 control devices 

per month discussed above will not be 

sufficient to satisfy NSPS requirements. 

We further believe the supply of 

combustors will lag demand. Due to 

their uncertainty, manufacturers will 

delay scaling-up production until they 

are confident of the requirements of the 

manufacturer test protocol, for which 

we are proposing certain revisions and 

clarifications in this action and intend 

to finalize later this year. Manufacturers 

also need to make sure their models will 

pass the test and will undergo a 

favorable review by the EPA before 

investing in scale-up of operations. The 

manufacturer test protocol is discussed 

in section VI.C below. 

The information available to the EPA 

leads us to conclude that, even with the 

uncertainty described above, the control 

device industry will be able to ramp up 

production each month by about 100 

units over the previous month, 

beginning now, with our proposed 

revisions to the manufacturer test 

protocol, to a production capacity of 

about 1,400 per month, or about 17,000 

per year, by April 15, 2014. With these 

projections in mind, it is clear that there 

will be an insufficient number of control 

devices on the market to meet the 

demand for control devices by the 

current compliance date of October 15, 

2013, in addition to the ongoing 

demand for control devices from units 

that become affected after October 15, 

2013. In fact, given these projections, it 

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is unlikely that supply of control 

devices will meet existing and new 

demand until 2016. 

We are concerned about delaying 

control of all storage vessels affected 

facilities until 2016. In order to move 

the compliance date to earlier than 

2016, and in an attempt to match supply 

and demand in the most efficient and 

environmentally protective manner, we 

are considering that the BSER 

constitutes measures other than 

immediate control for those that have 

come online to date (i.e., Group 1). 

Specifically, we are proposing a twopart requirement: (1) These sources 

provide initial notification to the EPA 

by October 15, 2013; and (2) for any of 

these storage vessels that experiences an 

event on or after April 12, 2013, that 

potentially results in emissions 

increasing, the owner or operator would 

be subject to the same control 

requirements as those in Group 2. 

The proposed approach not only 

would avoid delaying controlling all 

units until 2016, it would also help to 

some degree with proper allocation of 

the limited supplies of control devices 

in the near future and would ensure that 

those devices are used at the vessels 

expected to have the most significant 

emissions. As discussed in section 

VI.A.4 below, all oil and natural gas 

wells decline in production over time, 

with corresponding declines in reservoir 

pressure and liquids production. Often 

these declines are relatively rapid and 

can occur over a year or two. 

Accordingly, emissions from storage 

vessels in Group 1 may have declined 

significantly (potentially below the 6 

tpy threshold for some) by the time 

controls are available to all affected 

sources. We recognize, however, that 

the emissions of these Group 1 affected 

facilities could increase again due to an 

event leading to higher emissions (e.g., 

if an additional well comes online 

feeding the vessel or a well feeding the 

storage vessel is later refractured or 

otherwise stimulated leading to an 

increase in production). We are 

therefore proposing that, if such an 

increase occurs, the Group 1 sources 

comply with control requirements that 

apply to Group 2. 

Based upon the projected buildup of 

control device manufacturing capacity 

(i.e., an increase in production capacity 

of about 100 units per month, beginning 

now, to a production capacity of about 

1,400 per month, or about 17,000 per 

year, by April 15, 2014) and, if control 

is not required initially for Group 1, the 

EPA expects that by April 15, 2014, 

there will be sufficient supply of 

equipment for Group 2. Accordingly, we 

are proposing that Group 2 implement 

the control requirements by April 15, 

2014, or 60 days after startup, 

whichever is later. Additionally, the 

EPA believes manufacturers will be 

flexible in their ability to meet 

equipment demand increase in the 

future if crude oil and natural gas 

production increases. Because more 

controls will be applied to storage 

vessels as a result of this rule, the EPA 

believes that manufacturers will take 

advantage of scale economies and 

produce units at appropriate rates. We 

believe that the NSPS reconsideration, 

as proposed, will achieve environmental 

benefits while minimizing the risks of 

producers needing to slow activities to 

obtain appropriate equipment. 

In summary, based on the discussion 

of control supply and demand presented 

above, we are proposing differing 

requirements for storage vessels in 

Group 1 and those in Group 2 in order 

to ensure that controls are available for 

new or modified storage vessel as soon 

as possible after they come online (i.e., 

when they have higher emissions). 

Specifically, for Group 2 (i.e., those that 

are constructed, modified or 

reconstructed on or after April 12, 

2013), we propose to require reduction 

of emissions by 95 percent no later than 

60 days after startup or April 15, 2014, 

whichever is later. For Group 1 (i.e., 

those that were constructed, modified or 

reconstructed after August 23, 2011, and 

before April 12, 2013, many of which 

may have experienced decline in 

emissions, we are proposing a two-part 

requirement as reflecting BSER: (1) 

These sources provide initial 

notification to the EPA by October 15, 

2013; and (2) for any of these storage 

vessels that experience an event on or 

after April 12, 2013 that results in 

emissions increasing, the owner or 

operator would be subject to the same 

control requirements as those in Group 

2 and would have to control emissions 

no later than 60 days after the event or 

April 15, 2014, whichever is later. Until 

any such emissions increase, there 

would be no further requirements for 

Group 1 storage vessels. We have 

included above in the preamble and in 

the proposed regulatory text some 

examples of events that would 

potentially lead to emission increase. 

We solicit comment on other examples 

or suggestions on how to define these 

events in the rule. 

Further, we realize that the events 

discussed above that would likely lead 

to emissions increases are planned 

events. Operators of Group 1 storage 

vessels who plan for routing of 

additional wells to a storage vessel, 

fracturing or refracturing of a well 

feeding a storage vessel or other events 

are fully aware of such an event before 

it occurs. Therefore, we solicit comment 

on whether Group 1 storage vessels with 

increased emissions following such an 

event need the full 60 days provided for 

operators to apply controls. 

We believe, based on our analysis of 

control supply and demand discussed 

above, that sufficient supply of controls 

will be available for Group 2 storage 

vessels by April 15, 2014. As a result, 

we propose that the BSER for these 

Group 2 storage vessels would require 

reduction of emissions by 95 percent no 

later than 60 days after date of 

construction, modification or 

reconstruction or April 15, 2014, 

whichever is later. 

However, we are concerned with 

leaving affected sources with high 

emissions uncontrolled prior to April 

15, 2014, and certain Group 1 units after 

that date. One option is to require 

control for those with emissions above 

a certain level based on the number of 

available control devices during this 

period. However, we have insufficient 

information regarding the number of 

high throughput (and likely to have 

higher VOC emissions) storage vessels. 

Therefore, we are unable to identify an 

appropriate threshold higher than 6 tpy 

that would allow us to require control 

of higher emission storage vessels 

earlier. We are also concerned that this 

may impact the ability of other affected 

sources to acquire control devices and 

comply by April 15, 2014. We solicit 

information on the number of storage 

vessels at different throughput levels (or 

VOC emission levels) to further inform 

our consideration of controlling higher 

emitting storage vessels earlier than 

April 15, 2014. 

2. Definition of ‘‘Storage Vessel’’ 

In the final rule (77 FR 49490), the 

EPA defined ‘‘storage vessel,’’ in 

relevant part, as ‘‘a unit that is 

constructed primarily of nonearthen 

materials (such as wood, concrete, steel, 

fiberglass, or plastic) which provides 

structural support and is designed to 

contain an accumulation of liquids or 

other materials.’’ Several petitioners 

took issue with this definition and 

expressed particular concern that the 

storage vessel definition in the final rule 

inadvertently included nearly every 

container in the oil and gas production, 

natural gas processing, and natural gas 

transmission and storage segments. For 

example, one petitioner stated that the 

definition as written could potentially 

encompass a drinking water bottle. The 

petitioner stated further that while the 

drinking water bottle would not exceed 

the 6 tpy VOC potential emissions 

threshold, which was provided 

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elsewhere in the final rule, each site 

would have to maintain documentation 

on each and every container on-site to 

prove that the potential VOC emissions 

were less than 6 tpy. 

We agree that the current definition is 

unclear and propose to amend the 

definition of ‘‘storage vessel’’ in 

§ 60.5430 of the final rule to read, in 

relevant part, ‘‘a tank or other vessel 

that is designed to contain 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.’’ 

The proposed amended definition 

now specifically calls out the type of 

materials that must be stored in the 

vessel to meet the definition, thereby 

clarifying the scope of storage vessels 

the EPA intended to cover under the 

NSPS. The proposed definition reflects 

the EPA’s intent, as discussed in the 

original rulemaking. For example, in the 

discussion of our storage tank analysis 

in the preamble to the proposed rule, we 

stated that ‘‘[c]rude oil, condensate and 

produced water are typically stored in 

fixed-roof storage vessels.’’ 76 FR 52763. 

Similarly, in the preamble discussion of 

the estimated impacts, we addressed 

only vessels storing these types of 

materials. Thus, we indicated at 

proposal that our intent was to regulate 

only certain storage vessels (i.e., those 

storage vessels that may likely emit VOC 

emissions), not every container. 

We had previously believed that, by 

including a VOC emissions threshold in 

the storage vessel control requirements 

in § 60.5395 of the final rule, the rule 

effectively limited the applicability of 

the storage vessels emission standards 

to only storage vessels containing crude 

oil, condensate, intermediate 

hydrocarbon liquids, or produced water 

because, in all likelihood, only tanks 

storing these materials would have the 

potential to emit VOC at or above the 

threshold. However, as the petitioners 

pointed out, the definition in the final 

rule was stated in broad enough terms 

that a reasonable interpretation of the 

definition could lead to confusion as to 

which containers were considered to be 

storage vessels. If left unchanged, the 

storage vessel definition could result in 

a significant burden on the owner or 

operator because every container on-site 

may have to be identified and potential 

VOC emissions determined (and 

requisite records maintained). The 

proposed amendments to the storage 

vessel definition now limit the 

definition to vessels containing only 

those types of materials for which we 

originally intended the NSPS to apply. 

To provide further clarification, we are 

proposing to add definitions in 

§ 60.5430 for condensate, hydrocarbon 

liquid and produced water. We are 

proposing to adopt the definitions of 

these terms in 40 CFR part 63, subpart 

HH, which similarly requires 95-percent 

emission reduction from storage vessels 

that are major sources of hazardous air 

pollutants. 

3. Storage Vessel Affected Facility 

Definition at § 60.5365(e) 

In § 60.5365(e) of the final rule (77 FR 

49490), we described the affected 

facility as ‘‘[e]ach 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.’’ In 

§ 60.5395 of the final rule, we require 

affected facilities emitting more than 6 

tpy VOC to reduce VOC emissions by 

95.0 percent. 

Several petitioners stated that by not 

including the VOC emissions threshold 

in the affected facility definition, the 

EPA significantly increased the 

population of storage vessels potentially 

affected by the rule. The petitioners 

asserted that this very broad description 

of affected facility would result in 

unnecessary notification, recordkeeping 

and reporting burden, even if the storage 

vessels had no VOC emissions or are not 

subject to the control requirement. 

We had not intended to subject 

storage vessels emitting below the 6 tpy 

VOC to the NSPS. Although the final 

rule is clear that storage vessels that 

have always had a PTE below the 6 tpy 

threshold are not subject to the control 

requirement, the rule inadvertently 

requires them to comply with the 

recordkeeping and reporting 

requirements in the final rule, which are 

largely associated with demonstrating 

and assuring compliance with the 

control requirement. Further, having 

these storage vessels be subject to the 

NSPS could trigger state permitting 

requirements. We believe these 

associated burdens are not necessary for 

storage vessels with VOC emissions 

below 6 tpy, which are not subject to the 

control requirement. On the contrary, 

we believe it is important to limit the 

scope of the NSPS only to those storage 

vessels the EPA intended to control, 

thereby avoiding unnecessary 

unintended consequences. For the 

reason stated above, we agree with 

petitioners’ suggestion and are 

proposing to include the 6 tpy PTE 

threshold in the ‘‘storage vessel affected 

facility’’ definition in 60.5395(e). 

Petitioners asserted that a storage 

vessel’s emissions for purposes of 

applying the emissions threshold 

should consider any legal and 

practically enforceable emissions limit 

below 6 tpy. We are proposing to clarify 

at § 60.5365(e) that a source can take 

into account any legal and practically 

enforceable emissions limit under 

federal, state, local or tribal authority 

when determining the VOC emission 

rate for purposes of this threshold (i.e., 

they would not be subject to the storage 

vessel provisions of the NSPS if their 

potential to emit VOC was required to 

be less than 6 tpy under such limitation 

and they in fact were below that limit). 

In addition, petitioners had suggested 

that sources with a legal and practically 

enforceable requirement for at least 95 

percent control should not be affected 

facilities under the NSPS. The 

petitioners’ proposal seems to suggest 

that as long as an emission limitation 

equivalent to the NSPS emission 

standards can be enforced by state or 

another federal requirement, 

compliance with the NSPS is not 

necessary. The EPA is concerned 

regarding the absence of EPA oversight, 

which CAA section 111 contemplates. 

We are also concerned that such a broad 

proposition, if adopted, would not be 

limited to just this NSPS but may 

inadvertently impact other future EPA 

regulations as well. Although we are not 

proposing to add such a provision in 

this action, we solicit comment on the 

petitioners’ suggested approach, in 

particular on how the EPA may 

implement oversight of the enforcement 

of this NSPS and on distinguishing 

characteristics between this NSPS and 

other EPA regulations to warrant this 

approach here without inadvertently 

extending its use in other rulemakings. 

We also solicit comment if such an 

approach is permissible under CAA 

section 111. 

The final rule allows 30 days to 

determine emissions, followed by 

another 30 days to install controls, only 

for storage vessels located at well sites 

with no existing well in production. For 

storage vessels located at well sites with 

one or more wells in production, the 

NSPS allowed no time for determining 

emissions but required control on 

startup. This provision was based on the 

assumption that, for storage vessels at 

ongoing production sites, the owner or 

operator would be able to anticipate the 

rate and characteristics of the liquids 

entering the vessel, which would 

obviate the need for time for emissions 

determination and would allow the 

appropriate controls to be applied on 

startup if needed. Petitioners raised this 

provision as problematic and stated that 

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1Oil and Gas Production Facilities, Chapter 6, 

Section 2 Permitting Guidance. March 2010. 

the NSPS should provide time for 

emissions determination and control 

device installation for all storage 

vessels, not just ones at locations with 

no existing well in production. 

According to the petitioners, in many 

cases at well sites and at other locations, 

emissions cannot be estimated until the 

storage vessel is in operation, given the 

uncertainties in flowrate and other 

characteristics of the liquid flowing to 

the vessel. When a new well comes 

online, even at a location where wells 

are already in production, liquids from 

the new well can have significantly 

different characteristics than liquids 

from the existing wells. Further, 

petitioners noted that the language in 

the final rule could be incorrectly 

interpreted that only storage vessels 

located at well sites were potentially 

subject to the NSPS. In light of the new 

information, we propose that all new, 

modified or reconstructed Group 2 

storage vessels have up to 30 days after 

startup to determine the emissions rate 

and, if emissions are estimated to be 6 

tpy or more, controls must be in 

operation no later than 60 days from 

startup or by April 15, 2014, (our 

proposed new date for implementing 

control), whichever is later. It is our 

intent that the NSPS address VOC 

emissions from storage vessels located 

not only at wells but at any location 

from the well to the point of custody 

transfer to an oil pipeline or to the point 

of custody transfer from the natural gas 

transmission and storage segment to the 

local distribution company. 

Petitioners also asserted that 60 days 

was not a sufficient period to determine 

emissions and install controls if 

required, although they did not provide 

details supporting this assertion. We 

believe that 60 days is sufficient and 

propose to retain this period. We 

believe, since modeling is generally the 

method by which emissions are 

estimated, based on several parameters 

of the material entering the storage 

vessel, that 30 days is sufficient for 

determining whether emissions reach 

the threshold. Further, we believe that 

an additional 30 days is sufficient to 

install the combustor and the relatively 

simple associated closed vent system. 

We are also proposing to add a 

provision to clarify that a storage vessel 

affected facility whose VOC emissions 

decrease to less than the threshold of 6 

tpy, even for an extended time, will 

remain an affected facility. We believe 

this additional clarification is necessary, 

especially in light of our proposed 

alternative emission limit of less than 4 

tpy uncontrolled VOC emissions, to 

address the situation where emissions 

from a storage vessel affected facility 

declines and later increases. We believe 

it is important to clarify for both the 

regulated community and regulatory 

agencies that such a storage vessel 

remains an affected facility and would 

be required to meet the emission 

standards of either the 95 percent VOC 

reduction requirement or the proposed 

alternative emission limit of less than 4 

tpy VOC. This issue is related to the 

discussion below in section VI.A.4 

pertaining to continued control device 

use after extended periods of low 

emissions. 

One petitioner asserted that the final 

rule creates uncertainty because sources 

subject to the NSPS may trigger state 

minor or major source permitting 

requirements. Subsequently, the 

petitioner clarified that much of the 

uncertainty focuses on treatment of 

replacement storage vessels that are 

installed in cases of failure of existing 

storage vessels due to leakage or other 

issues. The petitioner was concerned 

that some state permitting programs 

require construction permits for sources 

that are affected facilities under any 

NSPS. Under subpart OOOO, a 

replacement storage vessel would be 

considered a new source and an affected 

facility if it has a PTE of 6 tpy or more 

and is put into service after August 23, 

2011. 

Although we understand that 

operators needing to install replacement 

tanks may potentially have difficulty 

meeting state permitting requirements, 

it is unclear how the NSPS could be 

revised to help address this issue. 

Accordingly, we solicit comment on 

how the NSPS could address the issue 

the petitioner raised. 

4. Alternative Mass-Based Standard for 

Storage Vessel Affected Facilities 

The petitioners pointed out that 

Wyoming 1 allows for control devices to 

be removed after sustained periods of 

uncontrolled emissions below the 

applicability threshold. The petitioners 

also contended that allowing control 

devices to be removed from lower 

emitting storage vessels would increase 

the number of control devices available 

to install on new storage vessels, which 

they assert would help alleviate the 

shortage of control devices discussed 

above in section VI.A.1. 

Although this proposed rule includes 

an amendment to assure adequate 

supply of control devices, the number of 

future storage vessel affected facilities 

that would require control is uncertain 

and may exceed our estimated 970 per 

month (which we relied on in our 

proposed amendment to address this 

issue). We believe that petitioners’ 

suggestion is a reasonable approach to 

help alleviate any potential control 

device shortage issue for the following 

reason. Storage vessels at oil and natural 

gas production sites are unlike many 

other sources in that emissions can 

reasonably be expected to decrease over 

time and, potentially, increase again 

under certain circumstances. After 

production declines, associated 

emissions would also decline. 

Petitioners’ suggestion would help build 

a buffer against supply shortage by 

allowing control devices on these low 

emitting storage vessels to be relocated 

to control emissions from storage 

vessels that have just come online and 

emitting above 6 tpy. For the reason 

stated above, we are proposing that 

affected sources meet either the 95 

percent VOC reduction standard or an 

alternative, mass-based numeric limit 

on uncontrolled emissions. 

Petitioners suggested that 6 tpy, the 

applicability threshold for storage vessel 

affected facilities under the NSPS, also 

be used as the threshold for 

uncontrolled emissions for allowing 

removal of storage devices. We disagree 

that 6 tpy is the appropriate alternative 

limit. In the final NSPS rule, we did not 

establish 6 tpy as an emission limit. 

Rather, 6 tpy is an applicability 

threshold, at which level we have 

determined that it is cost effective to 

require installation and operation of a 

control device to achieve 95 percent 

VOC reduction. At 6 tpy uncontrolled 

emissions, 95 percent control would 

result in an emission rate of 0.3 tpy. 

We think the appropriate limit would 

likely be something less than 4 tpy; we 

believe controlling storage vessels above 

that level could still achieve meaningful 

VOC reduction. We are therefore 

proposing to amend § 60.5395(a) to 

include both the existing VOC 

emissions reduction component and an 

alternative mass-based limit of less than 

4 tpy for uncontrolled emissions. The 

proposed uncontrolled emission limit 

would be available to those who can 

demonstrate, based on records for the 12 

months immediately preceding the 

demonstration and while the control is 

on, that the uncontrolled emissions 

during that 12 months period would 

have been below 4 tpy. This 

uncontrolled emission rate can be 

calculated using information available 

to the facility operator, including such 

parameters as separator pressure, liquid 

throughput and API gravity. We believe 

this alternate standard reflects the 

decline in production that all wells 

experience over time and allows control 

devices to be reused at other locations 

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which would help alleviate control 

device supply shortages. If, however, 

uncontrolled emissions increase to 4 tpy 

or above, the sources would need to 

once again comply with the 95 percent 

control requirement. 

As mentioned above, we are 

proposing to amend § 60.5395(a) to 

require sources to achieve either: (1) 95- 

percent VOC reduction; or (2) 

uncontrolled VOC emissions of less 

than 4 tpy. We are proposing that 

operators electing the alternative 

emission limit would be required to 

determine and keep records of the 

storage vessel’s emission rate at least 

monthly while operating under the 

alternative emissions limit. Similar to 

provisions in the final rule for 

determining annual emissions from 

storage vessels for applicability 

purposes, we propose that operators 

may use generally accepted models to 

estimate uncontrolled emissions. 

We solicit comment on our proposal 

to establish an alternative, mass-based 

numeric limit on uncontrolled 

emissions. We also solicit comment on 

whether a limit of less than 4 tpy is 

appropriate and, if not, what an 

appropriate limit would be, including 

any supporting data and rationale. In 

addition, we solicit comment on 

whether frequencies other than monthly 

would be appropriate for the emissions 

determinations while operating under 

the alternative emissions limit, whether 

the frequency of such determinations 

should decrease after some number of 

periodic estimates below 4 tpy, and 

whether the emissions determination 

should be required only after some 

event that would likely increase 

emissions. 

Under the final NSPS rule, owners 

and operators at well sites with no wells 

already in production have 30 days after 

determining emissions to procure and 

install control. As discussed elsewhere 

in this notice, we are proposing to 

provide such 30 days to owners and 

operators at all wells sites. We are 

similarly proposing here that, if a 

monthly emissions determination 

indicates VOC emissions of 4 tpy or 

greater, the owner or operator would 

need to comply with the 95 percent 

control standard by no later than 30 

days after the determination indicated 4 

tpy or greater VOC emissions. Under our 

proposed compliance demonstration 

requirement, the alternative emission 

limit would again be available for that 

storage vessel only after another 12 

months of uncontrolled VOC emissions 

less than 4 tpy while operating under 

the 95 percent VOC reduction 

requirement. 

While we think that owners and 

operators may need time to reinstall 

control, we are concerned with leaving 

the emissions unaddressed during that 

period. We therefore solicit comment on 

whether a 30 day period is needed for 

owners and operators to reinstall control 

and what appropriate measures should 

be taken during the period to control 

emissions. 

B. Periodic Monitoring and Testing of 

Closed-Vent Systems and Control 

Devices 

The final NSPS (77 FR 49490) 

requires that VOC emissions be reduced 

by 95 percent for storage vessel affected 

facilities with VOC emissions of 6 tpy 

or more. We had anticipated that most 

owners and operators will use a 

combustion control device to achieve 

the required level of emission reduction. 

The final NSPS requires an initial 

performance test, installation and 

operation of CPMS and calculation of 

daily averages of the continuously 

monitored parameters, among other 

requirements. As discussed above in 

section VI.A.1, we have revised our 

estimate of the number of storage 

vessels affected by the final rule from 

about 300 to approximately 11,600 per 

year. 

Several of the petitioners assert that 

the compliance monitoring 

requirements are overly complex and 

stringent given the large number 

affected storage vessels each year and 

the remoteness of the well sites at which 

they are installed. The petitioners argue 

that the well sites are unmanned for 

periods of time up to a month. 

According to the petitioners, proper 

operation of the CPMS and performance 

of other monitoring requirements would 

require specialized personnel to be onsite far more frequently. The petitioners 

also point out that most well sites do 

not have the communications and 

power infrastructure in place to operate 

the CPMS. 

The petitioners also argue that 

insufficient resources are available to 

perform the required Method 21 testing 

of the closed-vent systems and that 

lengthy (the NSPS requires a 2 hour 

observation) Method 22 testing of 

combustion control devices is 

unnecessary and overly burdensome. 

Based on our revised estimate of the 

number of storage vessel affected 

facilities, combined with our knowledge 

of the remoteness of these locations, we 

believe that petitioners have raised 

legitimate issues regarding the 

monitoring and testing requirements 

relative to control devices for storage 

vessels in the final NSPS rule and that 

these issues warrant our reconsideration 

of these requirements. The EPA also 

recognizes that delaying 

implementation of the storage vessel 

NSPS pending this reconsideration 

would further delay the important 

environmental benefits that will result 

from the NSPS. We are working with 

stakeholders to fully evaluate these 

issues and intend to complete our 

reconsideration of these monitoring and 

testing requirements by the end of 2014. 

The additional information discussed 

above has raised significant concerns 

that the compliance monitoring 

provisions and field testing provisions 

of the final rule may not be appropriate 

for this large number of affected storage 

vessels, which is much greater than we 

had expected and with many in remote 

locations. Therefore, we are proposing 

certain streamlined monitoring and 

continuous compliance demonstration 

requirements to provide assurance 

during the EPA’s reconsideration 

process, that closed-vent systems and 

control devices are designed and 

operated properly and that the control 

devices, when in use, are achieving the 

required 95 percent control. 

We believe the proposed requirements 

do not pose the concerns raised by the 

petitioners regarding burden imposed 

by the final rule due to the vast number 

of facilities and remote locations 

involved. The requirements we are 

proposing are intended to be carried out 

by personnel routinely at the well sites 

without the need for specialized 

training or instrumentation. 

Meanwhile, we will continue to fully 

evaluate the compliance demonstration 

and monitoring issues raised by the 

petitioners. We intend to complete our 

reconsideration of these requirements, 

along with other issues for which we 

intend to grant reconsideration, at a 

later date. 

As mentioned above, we are 

proposing a suite of streamlined 

compliance and monitoring 

requirements that would apply instead 

of the requirements in the final rule 

during the EPA’s reconsideration of 

associated issues. First, under § 60.5416, 

instead of the detailed Method 21 

monitoring requirements, the proposed 

requirements would include inspection 

requirements for covers and closed-vent 

systems. The proposed inspection 

requirements include monthly sensory 

(i.e., OVA) inspections of: (1) Closedvent system joints, seams and other 

sealed connections (e.g., welded joints); 

(2) other closed-vent system 

components such as peak pressure and 

vacuum valves; and (3) the physical 

integrity of tank thief hatches, covers, 

seals and pressure relief valves. 

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Second, under § 60.5417, instead of 

the CPMS requirements, the proposed 

requirements would include the 

following inspection requirements: (1) 

Monthly observation for visible smoke 

emissions employing section 11 of EPA 

Method 22 for a 15 minute period; (2) 

monthly visual inspection of the 

physical integrity of the control device; 

and (3) monthly check of the pilot flame 

and signs of improper operations. If the 

pilot flame is absent or if smoking is 

observed more than 1 minute during a 

15-minute period, then the operator 

must take further action to ascertain the 

cause of the malfunction, including 

checking the combustor air vent for 

obstructions and checking for liquid 

from the knockout drum reaching the 

combustor (i.e., the knockout drum is 

not draining properly). The owner or 

operator would be required to take 

corrective action as soon as practicable 

and as safely as possible after visible 

smoke emissions or other problems are 

observed. Each inspection of the storage 

vessel and associated control device and 

closed-vent system would be required to 

be documented in a logbook required to 

be kept securely on-site. Many storage 

vessels already have weatherproof 

containers mounted nearby where other 

records are kept. 

Third, we are proposing requirements 

that would apply instead of the field 

performance testing requirements in 

§ 60.5413. We are proposing to require 

that, where controls are used to reduce 

emissions, sources use control devices 

that by design can achieve 95 percent or 

more emission reduction and operate 

such devices according to the 

manufacturer’s instructions, procedures 

and maintenance schedule, including 

appropriate sizing of the combustor for 

the application. Documentation that a 

combustor is designed for at least 95 

percent control could include such 

items as manufacturer technical 

literature showing combustor 

performance, manufacturer’s guarantee 

of control efficiency, relevant test 

reports, etc. We are retaining and 

strongly encourage use of the option for 

operators to employ combustor models 

that pass manufacturer-conducted 

performance tests according to the EPA 

combustor test protocol. We believe that 

operators have an incentive to use 

manufacturer-tested combustors, since 

those combustors are not subject to 

subsequent performance tests. However, 

we seek comment on other potential 

approaches to provide incentive for 

operators to employ manufacturer-tested 

combustor models. 

We solicit input from the public and 

from states with relevant experience on 

the effectiveness of these types of 

streamlined monitoring techniques in 

assuring compliance with the emission 

reduction measures of the NSPS. 

Further, we encourage operators to 

document their experiences with these 

streamlined measures to better inform 

the EPA in its future evaluation of these 

measures. 

C. Test Protocol for Combustion Control 

Devices 

The proposed oil and natural gas 

sector NESHAP (76 FR 52738) included 

an option for manufacturers’ 

performance testing of certain 

combustion control devices as an 

alternative to on-site testing by the 

owner or operator. We explained the 

need for this alternative in the preamble 

to the proposed rule (see 76 FR 52785). 

The proposed NSPS also included this 

option. In order to promote consistency 

between the oil and natural gas sector 

NSPS and NESHAP, the proposed NSPS 

rule language referenced the relevant 

sections in the NESHAP (40 CFR 63, 

subpart HH) for the manufacturers’ test 

protocol. 

We received comments to the 

proposed rule indicating that the crossreferencing to the NESHAP was 

burdensome and posed other problems. 

In response, we eliminated the crossreferencing by incorporating the 

manufacturers’ performance test 

protocol from the NESHAP into the final 

NSPS. 

After publication of the final rule, 

some of the petitioners pointed out that 

the language we used in the final NSPS 

appeared to indicate that manufacturers’ 

performance testing is mandatory for all 

combustion control devices. The 

petitioners also noted inconsistencies 

between the regulatory language in the 

NSPS and NESHAP for the 

manufacturers’ performance test 

protocol. 

In response to the petitioners’ 

comments, we reviewed the 

manufacturers’ performance test 

protocol in the NSPS. We found that not 

all of the revisions made to the NESHAP 

protocol after proposal were carried 

over to the NSPS. These revisions 

involved modifications to the test 

procedures and reporting requirements. 

This inadvertent error led to most of the 

issues raised by the petitioners. It was 

the EPA’s intent to have essentially the 

same manufacturers’ performance test 

protocol and reporting requirements in 

both the NSPS and the NESHAP. 

In response, we are proposing to 

amend § 60.5413(d) to be consistent 

with the current requirements of 40 CFR 

63.772(h) to ensure consistency between 

the rules. This effort will also streamline 

testing, because enclosed combustor 

models that pass the test protocol will 

meet both the NSPS and NESHAP 

requirements, eliminating the need to 

test each model for NSPS and NESHAP 

compliance separately. 

Additionally, we are proposing to 

modify the reporting requirements for 

owners and operators using a 

manufacturer tested control device in 

the NSPS to match the same 

requirements in the NESHAP. We are 

proposing to revise § 60.5412(a)(i) to 

clarify that the manufacturers’ 

performance testing applies to the 

model of the combustion control device, 

not each individual control device. 

Finally, we are proposing to clarify that 

manufacturers’ performance testing is 

optional by revising § 60.5415(e)(2)(vii). 

As discussed in the 2011 proposed 

rule preamble (76 FR 52785), 

performance testing of control devices 

that are not configured with a distinct 

combustion chamber presents several 

technical issues that are more optimally 

addressed through manufacturer testing, 

and once these units are installed at a 

facility, through periodic inspection and 

maintenance in accordance with 

manufacturers’ recommendations. 

In the final rule (77 FR 49490), the 

EPA provided a path for compliance 

that involved operators purchasing 

certified combustors combined with 

annual compliance demonstrations. We 

would like to explore whether the 

compliance certification process could 

be made sufficiently robust to reduce or 

minimize future compliance 

demonstration obligations. We solicit 

comment on the desirability of such an 

approach and suggestions on how to 

design a sufficiently rigorous 

certification process to assure 

compliance while minimizing burden 

on both operators and implementing 

agencies. 

We are also soliciting comment on 

one potential framework for 

implementing the certification process 

for enclosed combustors used to meet 

the emissions standards under NSPS 

subpart OOOO and NESHAP subpart 

HH. The EPA notes that the following 

concept is one possible compliance tool, 

and welcomes comment on this or any 

other compliance tool incorporating an 

enclosed combustor certification 

program. We plan to continue to work 

with all stakeholders as we further 

develop this concept with the goal of 

ultimately designing a pathway that 

assures compliance without slowing 

responsible production of oil and 

natural gas. 

One possible compliance tool 

includes a requirement for owners or 

operators to use enclosed combustors 

that have been certified by the EPA. The 

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22136 Federal Register / Vol. 78, No. 71 / Friday, April 12, 2013 / Proposed Rules 

2Memorandum from Moore, Bruce, U.S. EPA, to 

Docket No. EPA–HQ–OAR–2010–0505, ‘‘Technical 

Corrections to the Final Oil and Natural Gas Sector 

New Source Performance Standards.’’ January 7, 

2013. 

manufacturer’s role would be to submit 

a performance test for each unique 

model manufactured. The manufacturer 

could submit the performance test to the 

EPA where it would be evaluated for 

completeness and compliance with the 

emissions standard required by the rule. 

In order to ease compliance, the EPA 

could require that the manufacturer’s 

control device be sold as ‘‘compliance 

ready’’; i.e. equipped with a 

thermocouple (or equivalent device) and 

data recorder. Initial discussions with 

control device manufacturers indicate 

that this may already be common 

practice. The EPA requests comment as 

to whether enclosed combustors could 

be sold as ‘‘compliance ready,’’ and 

whether such an approach would ease 

compliance. 

An owner or operator that purchases 

a certified control device could 

demonstrate initial compliance by 

providing proof of purchase of the EPAcertified device, in the form of a 

purchase order or receipt. The EPA 

could supplement such a requirement 

with a manufacturer reporting 

requirement providing the names of 

entities that had purchased certified 

control devices. Such a model of 

reporting may ensure that the purchase 

and installation of certified devices has 

occurred, and could also ensure 

compliance with the rule. 

The owner or operator could 

demonstrate ongoing compliance, in 

part, through monitoring of the presence 

of the continuous pilot flame. As 

discussed previously, a certified control 

device could be sold as ‘‘compliance 

ready’’; i.e., it would be equipped with 

a thermocouple (or equivalent device) 

and data recorder thereby simplifying 

the continuous compliance 

demonstration for the owner or 

operator. 

We welcome comment on this 

potential compliance option or on other 

compliance options. 

D. Annual Report and Compliance 

Certification 

Petitioners also asserted that the 30– 

day period to submit the annual report 

in § 60.5420(b) is too short because of 

the large number of affected facilities to 

be included in the annual reports of 

many companies and the requirement to 

have the reports signed by a responsible 

official. We agree that the 30-day period 

may be too short to compile all of the 

required information and properly 

inform a responsible official such that 

the official may certify the truth, 

accuracy and completeness of the 

annual report. Therefore, we are 

proposing to amend § 60.5420(b) to 

allow 90 days from the end of the 

compliance period for submittal of the 

annual report and compliance 

certification. This is consistent with 

Title V reporting and certification 

requirements. 

One petitioner pointed out that the 

public was not provided an opportunity 

to comment on the requirement in the 

final rule for certification by a 

responsible official and that such 

certification, modeled on Title V 

requirements, is not appropriate for the 

oil and natural gas sector due to the 

number of sources involved and other 

factors. We have reconsidered the 

certification requirement and, for the 

same reasons provided in the final rule 

preamble (77 FR 49527), we are 

proposing to retain this requirement. 

Specifically, we believe that selfcertification is an important mechanism 

for assuring the public that the 

information submitted by each facility is 

accurate. In addition, the Title V 

program has successfully employed selfcertification since its inception and we 

believe it is a good model for the 

certification provisions in the final rule. 

For these reasons, we are proposing to 

retain the certification provision in the 

final rule. 

We believe that the petitioner’s main 

concern may have been the 30-day 

period allowed for submittal of the 

certification, which the petitioner 

claimed insufficient in light of the 

number of affected sources. As 

discussed above, we are proposing to 

allow 90 days for submitting the 

compliance certification. 

E. Properly Designed Storage Vessels, 

Closed-Vent Systems and Control 

Devices 

It is the EPA’s experience that proper 

design and sizing of storage vessels and 

their associated closed-vent systems and 

control devices are important 

considerations in effective control of 

VOC emissions from storage vessels. For 

example, such factors as type of gasket 

material, weighting of thief hatch 

covers, release point of pressure relief 

valves, sizing of the storage vessel itself, 

diameter of lines conveying vapor to the 

control device, sizing of the control 

device and other factors can greatly 

affect the ability of the system to 

achieve the control efficiency required 

by the NSPS. Improper design or 

operation of the storage vessel and its 

control system can result in occurrences 

where peak flow overwhelms the 

storage vessel and its capture systems, 

resulting in emissions that do not reach 

the control device, effectively reducing 

the control efficiency. We believe that it 

is essential that operators employ 

properly designed, sized and operated 

storage vessels to achieve effective 

emissions control. We believe that such 

efforts on the part of owners and 

operators can result in more effective 

control of VOC emissions from storage 

vessels subject to the NSPS. Although 

we are not proposing today to add 

requirements for proper design of 

storage vessels and associated closedvent systems and control devices, we 

solicit comment on whether such 

provisions should be included in the 

final rule. 

VII. Technical Corrections and 

Clarifications 

Following publication of the final 

NSPS, we subsequently determined, 

following review of the petitions and 

discussions with affected parties, that 

the final rule warrants correction 

clarification in certain areas. The EPA is 

proposing corrections to applicability 

dates and monitoring, recordkeeping 

and reporting requirements for all 

affected facilities. In addition, we are 

proposing corrections that are editorial 

in nature including typographical and 

grammatical errors, as well as incorrect 

cross-references. Details of the specific 

changes we are proposing to the 

regulatory text may be found in the 

docket for this action.2

VIII. Impacts of This Proposed Rule 

Our analysis shows that owners and 

operators of storage vessel affected 

facilities would choose to install and 

operate the same or similar air pollution 

control technologies under the proposed 

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 

controls for this proposed rule that they 

would have for the original final rule, 

there should not be any incremental 

costs related to this proposed revision. 

A. What are the air impacts? 

We believe that owners and operators 

of storage vessel affected facilities will 

install the same or similar control 

technologies to comply with the revised 

standards proposed in this action as 

they would have installed to comply 

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with the previously finalized standards. 

Accordingly, we believe that this 

proposed rule will not result in 

significant changes in emissions of any 

of the regulated pollutants. 

B. What are the energy impacts? 

This proposed 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 storage vessel 

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 proposed rule because owners 

and operators of storage vessel 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 storage vessel affected 

facilities would install the same or 

similar control technologies to meet the 

standards proposed in this action as 

they would have chosen to comply with 

the previously finalized standards, we 

do not anticipate that this proposed 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 proposed 

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 

proposal and we do not anticipate any 

significant emission changes resulting 

from this rule. Therefore, there are no 

direct monetized benefits or disbenefits 

associated with this proposed rule. 

IX. Statutory and Executive Order 

Reviews 

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’’ under the terms of 

Executive Order 12866 (58 FR 51735, 

October 4, 1993) and is therefore not 

subject to review under Executive 

Orders 12866 and 13563 (76 FR 3821, 

January 21, 2011). 

A RIA was prepared for the April 

2012 final rule and can be found at: 

http://www.epa.gov/ttn/ecas/regdata/ 

RIAs/oil_natural_gas_final_neshap_

nsps_ria.pdf. Because this action does 

not impose new compliance costs on 

affected sources, we project that this 

rule will result in no significant change 

in costs, emission reductions or benefits 

in 2015, the year of full implementation 

of the NSPS. 

B. Paperwork Reduction Act 

This action does not impose any new 

information collection burden. Today’s 

notice of reconsideration does not 

change the information collection 

requirements previously finalized and, 

as a result, does not impose any 

additional burden on industry. 

However, OMB has previously approved 

the information collection requirements 

contained in the existing regulations 

(see 77 FR 49490) under the provisions 

of the PRA, 44 U.S.C. 3501, et seq., and 

has assigned OMB control number 

2060–0673). The OMB control numbers 

for the EPA’s regulations are listed in 40 

CFR part 9 and 48 CFR chapter 15. 

C. Regulatory Flexibility Act 

The RFA generally requires an agency 

to prepare a regulatory flexibility 

analysis of any rule subject to notice 

and comment rulemaking requirements 

under the Administrative Procedure Act 

or any other statute unless the agency 

certifies that the rule will not have a 

significant economic impact on a 

substantial number of small entities. 

Small entities include small businesses, 

small organizations, and small 

governmental jurisdictions. 

For purposes of assessing the impacts 

of this rule on small entities, a small 

entity is defined as: (1) A small business 

in the oil or natural gas industry whose 

parent company has no more than 500 

employees (or revenues of less than $7 

million for firms that transport natural 

gas via pipeline); (2) a small 

governmental jurisdiction that is a 

government of a city, county, town, 

school district, or special district with a 

population of less than 50,000; and (3) 

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this proposed rule on small 

entities, I certify that this action will not 

have a SISNOSE. In determining 

whether a rule has a SISNOSE, the 

impact of concern is any significant 

adverse economic impact on small 

entities, since the primary purpose of 

the regulatory flexibility analyses is to 

identify and address regulatory 

alternatives ‘‘which minimize any 

significant economic impact of the rule 

on small entities.’’ 5 U.S.C. 603 and 604. 

Thus, an agency may certify that a rule 

will not have a SISNOSE if the rule 

relieves regulatory burden, or otherwise 

has a positive economic effect on all of 

the small entities subject to the rule. 

The EPA has determined that none of 

the small entities will experience a 

significant impact because the notice of 

reconsideration imposes no additional 

compliance costs on owners or 

operators of affected sources. We have 

therefore concluded that today’s notice 

of reconsideration will not result in a 

SISNOSE. We continue to be interested 

in the potential impacts of the proposed 

rule on small entities and welcome 

comments on issues related to such 

impacts. 

D. Unfunded Mandates Reform Act of 

1995 

This action contains no federal 

mandates under the provisions of Title 

II of the UMRA of 1995, 2 U.S.C. 1531– 

1538 for state, local or tribal 

governments or the private sector. The 

action imposes no enforceable duty on 

any state, local or tribal governments or 

the private sector. Therefore, this action 

is not subject to the requirements of 

sections 202 or 205 of the UMRA. 

This rule is also not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. This 

action contains no requirements that 

apply to such governments nor does it 

impose obligations upon them. 

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, as specified in 

Executive Order 13132. This proposal is 

a reconsideration of an existing rule and 

imposes no new impacts or costs. Thus, 

Executive Order 13132 does not apply 

to this action. 

In the spirit of Executive Order 13132, 

and consistent with EPA policy to 

promote communications between the 

EPA and state and local governments, 

the EPA specifically solicits comment 

on this proposed action from state and 

local officials. 

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F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). 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. 

The EPA specifically solicits 

additional comment on this proposed 

action from tribal officials. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

This action is not subject to Executive 

Order 13045 (62 FR 19885, April 23, 

1997) because it is not economically 

significant as defined in Executive 

Order 12866, and because the agency 

does not believe the environmental 

health risks or safety risks addressed by 

this action present a disproportionate 

risk to children. This action has no 

impacts thus health and risk 

assessments were not conducted. 

The public is invited to submit 

comments or identify peer-reviewed 

studies and data that assess effects of 

early life exposure to HAP from oil and 

natural gas sector activities. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211 (66 FR 28355 (May 22, 

2001)), because it is not a significant 

regulatory action under Executive Order 

12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the NTTAA, Public 

Law 104–113, 12(d) (15 U.S.C. 272 note) 

directs the EPA to use VCS in its 

regulatory activities unless to do so 

would be inconsistent with applicable 

law or otherwise impractical. Voluntary 

consensus standards are technical 

standards (e.g., materials specifications, 

test methods, sampling procedures and 

business practices) that are developed or 

adopted by VCS bodies. The NTTAA 

directs the EPA to provide Congress, 

through OMB, explanations when the 

agency decides not to use available and 

applicable VCS. 

This proposed rulemaking does not 

involve technical standards. Therefore, 

the EPA is not considering the use of 

any VCS. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629 

(Feb. 16, 1994)) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies and activities on minority 

populations and low-income 

populations in the United States. 

The EPA has determined that this 

proposed rule will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations 

because it does not affect the level of 

protection provided to human health or 

the environment. This proposal is a 

reconsideration of an existing rule and 

imposes no new impacts or costs. 

List of Subjects in 40 CFR Part 60 

Administrative practice and 

procedure, Air pollution control, 

Incorporation by reference, 

Intergovernmental relations, Reporting 

and recordkeeping. 

Dated: March 28, 2013. 

Bob Perciasepe, 

Acting Administrator. 

For the reasons set out in the 

preamble, Title 40, chapter I of the Code 

of Federal Regulations is proposed to be 

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 taking into 

account requirements under a legally 

and practically enforceable limit in an 

operating permit or by other 

mechanism. 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. A storage 

vessel that has been determined in 

accordance with § 60.5395(c) to have a 

potential to emit of less than 6 tpy is not 

a storage vessel affected facility, 

provided that the owner or operator has 

maintained record of such 

determination. 

* * * * * 

■ 3. Section 60.5380 is amended by: 

■ a. Revising paragraph (a)(2); and 

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

The revisions read as follows: 

§ 60.5380 What standards apply to 

centrifugal compressor affected facilities? 

* * * * * 

(a) * * * 

(2) If you use a control device to 

reduce emissions, you must equip the 

wet seal fluid degassing system with a 

cover that meets the requirements of 

§ 60.5411(b), that is connected through 

a closed vent system that meets the 

requirements of § 60.5411(a) and routed 

to a control device that meets the 

conditions specified in § 60.5412(a), (b) 

and (c). As an alternative to routing the 

closed vent system to a control device, 

you may route the closed vent system to 

a flow line, as defined in § 60.5430. 

(b) You must demonstrate initial 

compliance with the standards that 

apply to centrifugal compressor affected 

facilities as required by § 60.5410(b). 

(c) You must demonstrate continuous 

compliance with the standards that 

apply to centrifugal compressor affected 

facilities as required by § 60.5415(b). 

* * * * * 

■ 4. Section 60.5390 is amended by: 

■ a. Revising the introductory text; 

■ b. Revising paragraph (a); and 

■ c. Revising paragraphs (c)(1) and (2). 

The revisions read as follows: 

§ 60.5390 What standards apply to 

pneumatic controller affected facilities? 

For each pneumatic controller 

affected facility you must comply with 

the VOC standards, based on natural gas 

as a surrogate for VOC, in either 

paragraph (b)(1) or (c)(1) of this section, 

as applicable. Pneumatic controllers 

meeting the conditions in paragraph (a) 

of this section are exempt from this 

requirement. However, you must 

comply with the requirements in either 

paragraph (b)(2) or (c)(2), as applicable. 

(a) The requirements of paragraph 

(b)(1) or (c)(1) of this section are not 

required if you determine that the use 

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of a pneumatic controller affected 

facility with a bleed rate greater than the 

applicable standard is required based on 

functional needs, including but not 

limited to response time, safety and 

positive actuation. 

* * * * * 

(c)(1) 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 have a bleed rate 

less than or equal to 6 standard cubic 

feet per hour. 

(2) Each pneumatic controller affected 

facility 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). 

* * * * * 

■ 5. Section 60.5395 is revised to read 

as follows: 

§ 60.5395 What standards apply to storage 

vessel affected facilities? 

Except as provided in paragraph (h) of 

this section, you must comply with the 

standards in this section for each storage 

vessel affected facility. 

(a)(1) If you are the owner or operator 

of a Group 1 storage vessel affected 

facility as defined in this subpart, you 

must comply with paragraph (b) of this 

section. 

(2) If you are the owner or operator of 

a Group 2 storage vessel affected facility 

as defined in this subpart, you must 

comply with paragraphs (c) through (g) 

of this section. 

(b) Requirements for Group 1 storage 

vessel affected facilities. (1) You must 

submit a notification identifying each 

Group 1 storage vessel, including its 

location, by October 15, 2013. 

(2) On or after April 12, 2013, if you 

have an event that could reasonably be 

expected to increase VOC emissions 

from your Group 1 storage vessel, you 

must comply with paragraphs (d) 

through (g) of this section. For the 

purposes of this section, an event 

includes, but is not limited to, the 

examples specified in paragraphs 

(b)(2)(i) through (iv) of this section. 

(i) Routing a well to the storage vessel 

that was not previously routed to the 

storage vessel. 

(ii) Conducting hydraulic fracturing 

on a well routed to the storage vessel. 

(iii) Conducting hydraulic refracturing 

on a well routed to the storage vessel. 

(iv) Any other event that could 

increase the VOC emissions from the 

storage vessel affected facility. 

(c) Emissions determination. You 

must comply with paragraphs (c)(1) or 

(2) of this section. 

(1) For Group 2 storage vessels 

constructed, modified or reconstructed 

before April 15, 2014, you must 

determine the VOC emission rate no 

later than April 15, 2014, or 30 days 

after startup, whichever is later. To 

make this determination, you must use 

any generally accepted model or 

calculation methodology. If the VOC 

emission rate is determined to be equal 

to 6 tpy or greater, you must comply 

with paragraphs (d) through (g) of this 

section. 

(2) For Group 2 storage vessels 

constructed on or after April 15, 2014, 

you must determine the VOC emission 

rate using any generally accepted model 

or calculation methodology within 30 

days after startup and minimize 

emissions to the extent practicable 

during the 30-day period using good 

engineering practices through the period 

prior to installation of control. If the 

VOC emission rate is determined to be 

equal to 6 tpy or greater, you must 

comply with paragraphs (d) through (g) 

of this section. 

(d) You must comply with the 

requirements of paragraph (d)(1) or (2) 

of this section. 

(1) Reduce VOC emissions by 95.0 

percent or greater by April 15, 2014 or 

within 60 days after startup, whichever 

is later. 

(2) Maintain the VOC emissions from 

the storage vessel affected facility at less 

than 4 tpy without considering control, 

provided that you have been using a 

control device and have demonstrated 

that the VOC emissions have been 

below 4 tpy without considering control 

for at least the 12 consecutive months 

immediately preceding the 

demonstration. You must determine the 

VOC emission rate each month using 

any generally accepted model or 

calculation methodology and minimize 

emissions to the extent practicable 

during this period using good 

engineering practice. Monthly 

calculations must be separated by at 

least 14 days. 

(e) Control requirements. (1) Except as 

required in paragraph (e)(2) of this 

section, if you use a control device 

(such as an enclosed combustion device 

or vapor recovery device) to reduce 

emissions from your storage vessel 

affected facility, you must equip the 

storage vessel with a cover that meets 

the requirements of § 60.5411(b) and is 

connected through a closed vent system 

that meets the requirements of 

§ 60.5411(c), and you must route 

emissions to a control device that meets 

the conditions specified in § 60.5412(c) 

and (d). As an alternative to routing the 

closed vent system to a control device, 

you may route the closed vent system to 

a flow line, as defined in § 60.5430. If 

you route emissions to a flow line, you 

must equip the storage vessel with a 

cover that meets the requirements of 

§ 60.5411(b) and is connected through a 

closed vent system that meets the 

requirements of § 60.5411(c). 

(2) If you use a floating roof to reduce 

emissions, you must meet the 

requirements of § 60.112b(a)(1) or (2) 

and the relevant monitoring, inspection, 

recordkeeping, and reporting 

requirements in 40 CFR part 60, subpart 

Kb. 

(f) Reserved. 

(g) Compliance, notification, 

recordkeeping, and reporting. If you use 

a control device to reduce emissions or 

if you route your emissions to a flow 

line, you must comply with paragraphs 

(g)(1) and (2) of this section. 

(1) You must demonstrate initial 

compliance with standards as required 

by § 60.5410(h). 

(2) You must demonstrate continuous 

compliance with standards as required 

by § 60.5415(e)(3). 

(3) You must perform the required 

notification, recordkeeping, and 

reporting as required by § 60.5420. 

(h) Exemptions. This subpart does not 

apply to storage vessels subject to and 

controlled in accordance with the 

requirements for storage vessels in 40 

CFR part 60, subpart Kb, 40 CFR part 63, 

subparts G, CC, HH, or WW. 

■ 6. Section 60.5410 is amended by: 

■ a. Revising the introductory text; 

■ b. Revising paragraphs (a)(3) and (4); 

■ c. Revising paragraphs (b)(2) through 

(5); 

■ d. Revising paragraphs (b)(7) and (8); 

■ e. Revising paragraph (d) introductory 

text; 

■ f. Revising paragraphs (d)(1) and (2); 

■ g. Revising paragraph (d)(4); 

■ h. Removing and reserving paragraph 

(e); and 

■ i. Adding paragraphs (h) and (i). 

The revisions and addition 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? 

You must determine initial 

compliance with the standards for each 

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22140 Federal Register / Vol. 78, No. 71 / Friday, April 12, 2013 / Proposed Rules 

affected facility using the requirements 

in paragraphs (a) through (i) of this 

section. The initial compliance period 

begins on October 15, 2012, or upon 

initial startup, whichever is later, and 

ends no later than one year after the 

initial startup date for your affected 

facility or no later than one year after 

October 15, 2012. The initial 

compliance period may be less than one 

full year. 

(a) * * * 

(3) You must maintain a log of records 

as specified in § 60.5420(c)(1)(i) through 

(iv) for each well completion operation 

conducted during the initial compliance 

period. 

(4) For each gas well affected facility 

subject to both § 60.5375(a)(1) and (3), 

as an alternative to retaining the records 

specified in § 60.5420(c)(1)(i) through 

(iv), you may maintain records of one or 

more digital photographs with the date 

the photograph was taken and the 

latitude and longitude of the well site 

imbedded within or stored with the 

digital file showing the equipment for 

storing or re-injecting recovered liquid, 

equipment for routing recovered gas to 

the gas flow line and the completion 

combustion device (if applicable) 

connected to and operating at each gas 

well completion operation that occurred 

during the initial compliance period. As 

an alternative to imbedded latitude and 

longitude within the digital photograph, 

the digital photograph may consist of a 

photograph of the equipment connected 

and operating at each well completion 

operation with a photograph of a 

separately operating GIS device within 

the same digital picture, provided the 

latitude and longitude output of the GIS 

unit can be clearly read in the digital 

photograph. 

(b) * * * 

(2) If you use a control device to 

reduce emissions, you must equip the 

wet seal fluid degassing system with a 

cover that meets the requirements of 

§ 60.5411(b) that is connected through a 

closed vent system that meets the 

requirements of § 60.5411(a) and is 

routed to a control device that meets the 

conditions specified in § 60.5412(a), (b) 

and (c). As an alternative to routing the 

closed vent system to a control device, 

you may route the closed vent system to 

a flow line, as defined in § 60.5430. 

(3) You must conduct an initial 

performance test as required in 

§ 60.5413 within 180 days after initial 

startup or by October 15, 2012, 

whichever is later, and you must 

comply with the continuous compliance 

requirements in § 60.5415(b)(1) through 

(3). 

(4) You must conduct the initial 

inspections required in § 60.5416(a) and 

(b). 

(5) You must install and operate the 

continuous parameter monitoring 

systems in accordance with § 60.5417(a) 

through (g), as applicable. 

* * * * * 

(7) You must submit the initial annual 

report for your centrifugal compressor 

affected facility as required in 

§ 60.5420(b)(3) for each centrifugal 

compressor affected facility. 

(8) You must maintain the records as 

specified in § 60.5420(c)(2). 

* * * * * 

(d) To achieve initial compliance with 

emission standards for your pneumatic 

controller affected facility you must 

comply with the requirements specified 

in paragraphs (d)(1) through (6) of this 

section, as applicable. 

(1) You must demonstrate initial 

compliance by maintaining records as 

specified in § 60.5420(c)(4)(ii) of your 

determination that the use of a 

pneumatic controller affected facility 

with a bleed rate greater than 6 standard 

cubic feet of gas per hour is required as 

specified in § 60.5390(a). 

(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. 

(3) * * * 

(4) You must tag each new pneumatic 

controller affected facility according to 

the requirements of § 60.5390(b)(2) or 

(c)(2). 

* * * * * 

(e) [Reserved] 

* * * * * 

(h) For each storage vessel affected 

facility that is subject to § 60.5395(d), 

you must comply with paragraphs (h)(1) 

through (5) of this section. 

(1) You must determine the VOC 

emission rate within 30 days after 

startup. You must use good engineering 

practices to minimize emissions during 

the 30-day period. 

(2) You must reduce VOC emissions 

by 95.0 percent or greater within 60 

days after startup or by April 15, 2014, 

whichever is later. 

(3) If you use a control device to 

reduce emissions, or if you route 

emissions to a flow line, you must 

demonstrate initial compliance by 

meeting the requirements in paragraphs 

(h)(3)(i) and (ii) of this section. For a 

Group 1 storage vessel affected facility, 

you must demonstrate initial 

compliance within 30 days after an 

event (as provided in § 60.5395(b)) or by 

April 15, 2014, whichever is later. For 

a Group 2 storage vessel affected 

facility, you must demonstrate initial 

compliance within 60 days after startup 

or by April 15, 2014, whichever is later. 

(i) You must equip the storage vessel 

with a cover that meets the 

requirements of § 60.5411(b) and is 

connected through a closed vent system 

that meets the requirements of 

§ 60.5411(c). 

(ii) You must route the closed vent 

system to a control device that meets the 

conditions specified in § 60.5412(c) and 

(d) or to a flow line, as defined in 

§ 60.5430. 

(4) You must submit the information 

required for your storage vessel affected 

facility in paragraphs (h)(4)(i) through 

(iii) of this section in the initial annual 

report required in § 60.5420(b). 

(i) The results of the emissions 

determination conducted under 

§ 60.5395(b) or (c), as applicable, and 

the methodology used to determine 

emissions. 

(ii) A statement that you have met the 

requirements of paragraph (h)(2) of this 

section. 

(iii) A statement that you have met the 

emissions standards in § 60.5395(d). 

(5) You must maintain the records 

required for your storage vessel affected 

facility, as specified in § 60.5420(c)(5) 

for each storage vessel affected facility. 

(i) For each Group 1 storage vessel, 

you must submit a notification 

identifying each storage vessel, 

including its location by October 15, 

2013. If you have an event that results 

in VOC emissions from the Group 1 

storage vessel equal to or greater than 6 

tpy after April 12, 2013, as specified in 

§ 60.5395(b), you must comply with 

paragraph (h) of this section. 

■ 7. Section 60.5411 is amended by: 

■ a. Revising the section heading; 

■ b. Revising paragraph (a) introductory 

text; 

■ c. Revising paragraph (a)(1); 

■ d. Revising paragraph (a)(3)(i)(A); 

■ e. Revising paragraph (b) introductory 

text; 

■ f. Revising paragraph (b)(1); 

■ g. Revising paragraph (b)(2)(iv); 

■ h. Adding paragraph (b)(3); and 

■ i. Adding paragraph (c). 

The revisions and additions 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 and 

centrifugal compressor wet seal degassing 

systems? 

* * * * * 

(a) Closed vent system requirements 

for centrifugal compressor wet seal 

degassing systems. (1) You must design 

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the closed vent system to route all gases, 

vapors, and fumes emitted from the 

material in the wet seal fluid degassing 

system to a control device that meets the 

requirements specified in § 60.5412(a) 

through (c). 

* * * * * 

(3) * * * 

(i) * * * 

(A) You must properly install, 

calibrate, maintain, and operate a flow 

indicator at the inlet to the bypass 

device that could divert the stream away 

from the control device or flow line to 

the atmosphere that is capable of taking 

periodic readings as specified in 

§ 60.5416(a)(4) and sounds an alarm 

when the bypass device is open such 

that the stream is being, or could be, 

diverted away from the control device to 

the atmosphere. 

* * * * * 

(b) Cover requirements for storage 

vessels and centrifugal compressor wet 

seal degassing systems. (1) The cover 

and all openings on the cover (e.g., 

access hatches, sampling ports, pressure 

relief valves and gauge wells) shall form 

a continuous barrier over the entire 

surface area of the liquid in the storage 

vessel or wet seal fluid degassing 

system. 

(2) * * * 

(iv) To vent liquids, gases, or fumes 

from the unit through a closed-vent 

system to a control device designed and 

operated in accordance with the 

requirements of paragraph (a) of this 

section or to a flow line, as defined in 

§ 60.5430. 

(3) Each storage vessel thief hatch 

shall be weighted and 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 flow line. (1) You must 

design the closed vent system to route 

all gases, vapors, and fumes emitted 

from the material in the storage vessel 

to a control device that meets the 

requirements specified in § 60.5412(c) 

and (d), or to a flow line, as defined in 

§ 60.5430. 

(2) You must design and operate the 

closed vent system with no detectable 

emissions, as determined using 

olfactory, visual and auditory 

inspections. 

(3) You must meet the requirements 

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

of this section if the closed vent system 

contains one or more bypass devices 

that could be used to divert all or a 

portion of the gases, vapors, or fumes 

from entering the control device or to a 

flow line, as defined in § 60.5430. 

(i) Except as provided in paragraph 

(c)(3)(ii) of this section, you must 

comply with either paragraph 

(c)(3)(i)(A) or (B) of this section for each 

bypass device. 

(A) You must properly install, 

calibrate, maintain, and operate a flow 

indicator at the inlet to the bypass 

device that could divert the stream away 

from the control device or flow line to 

the atmosphere that sounds an alarm 

when the bypass device is open such 

that the stream is being, or could be, 

diverted away from the control device 

or flow line to the atmosphere. 

(B) You must secure the bypass device 

valve installed at the inlet to the bypass 

device in the non-diverting position 

using a car-seal or a lock-and-key type 

configuration. 

(ii) Low leg drains, high point bleeds, 

analyzer vents, open-ended valves or 

lines, and safety devices are not subject 

to the requirements of paragraph (c)(3)(i) 

of this section. 

■ 8. Section 60.5412 is amended by: 

■ a. Revising paragraph (a) introductory 

text; 

■ b. Revising paragraph (a)(1) 

introductory text; 

■ c. Revising paragraph (a)(2); 

■ d. Revising paragraph (b); 

■ e. Revising paragraph (c) introductory 

text; 

■ f. Revising paragraph (c)(1); and 

■ g. Adding paragraph (d). 

The revisions and addition 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? 

* * * * * 

(a) Each control device used to meet 

the emission reduction standard in 

§ 60.5380(a)(1) for your centrifugal 

compressor affected facility, must be 

installed according to paragraphs (a)(1) 

through (3) of this section. As an 

alternative, for a centrifugal compressor 

affected facility, 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). 

(1) Each enclosed combustion device 

(e.g., thermal vapor incinerator, catalytic 

vapor incinerator, boiler, or process 

heater) must be designed and operated 

in accordance with one of the 

performance requirements specified in 

paragraphs (a)(1)(i) through (iv) of this 

section. 

* * * * * 

(2) Each vapor recovery device (e.g., 

carbon adsorption system or condenser) 

or other non-destructive control device 

must be designed and operated to 

reduce the mass content of VOC in the 

gases vented to the device by 95.0 

percent by weight or greater as 

determined in accordance with the 

requirements of § 60.5413. As an 

alternative to the performance testing 

requirements, you may demonstrate 

initial compliance by conducting a 

design analysis for vapor recovery 

devices according to the requirements of 

§ 60.5413(c). 

* * * * * 

(b) You must operate each control 

device installed on your centrifugal 

compressor affected facility in 

accordance with the requirements 

specified in paragraphs (b)(1) and (2) of 

this section. 

(1) You must operate each control 

device used to comply with this subpart 

at all times when gases, vapors, and 

fumes are vented from the wet seal fluid 

degassing system affected facility, as 

required under § 60.5380(a), through the 

closed vent system to the control device. 

You may vent more than one affected 

facility to a control device used to 

comply with this subpart. 

(2) For each control device monitored 

in accordance with the requirements of 

§ 60.5417(a) through (g), you must 

demonstrate compliance according to 

the requirements of § 60.5415(b)(2), as 

applicable. 

(c) For each carbon adsorption system 

used as a control device to meet the 

requirements of paragraph (a)(2) or 

(d)(2) of this section, you must manage 

the carbon in accordance with the 

requirements specified in paragraphs 

(c)(1) or (2) of this section. 

(1) Following the initial startup of the 

control device, you must replace all 

carbon in the control device with fresh 

carbon on a regular, predetermined time 

interval that is no longer than the 

carbon service life established according 

to § 60.5413(c)(2) or (3) or according to 

the design analysis in paragraph (d)(2) 

of this section, for the carbon adsorption 

system. You must maintain records 

identifying the schedule for replacement 

and records of each carbon replacement 

as required in § 60.5420(c)(10) and (13). 

* * * * * 

(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, 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). 

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22142 Federal Register / Vol. 78, No. 71 / Friday, April 12, 2013 / Proposed Rules 

(1) Each enclosed combustion device 

(e.g., thermal vapor incinerator, catalytic 

vapor incinerator, boiler, or process 

heater) must be designed to reduce the 

mass content of VOC emissions by 95.0 

percent or greater. You must follow the 

requirements in paragraphs (d)(1)(i) 

through (iii) of this section. 

(i) Ensure that each enclosed 

combustion device is maintained in a 

leak free condition. 

(ii) Install and operate a continuous 

burning pilot flame. 

(iii) Operate the enclosed combustion 

device with no visible emissions, except 

for periods not to exceed a total of one 

minute during any 15 minute period. A 

visible emissions test using section 11 of 

EPA Method 22, 40 CFR part 60, 

Appendix A, must be performed at least 

once every calendar month, separated 

by at least 15 days between each test. 

The observation period shall be 15 

minutes. Devices failing the visible 

emissions test must follow 

manufacturer’s repair instructions, if 

available, or best combustion 

engineering practice as outlined in the 

unit inspection and maintenance plan, 

to return the unit to compliant 

operation. All inspection, repair and 

maintenance activities for each unit 

must be recorded in a maintenance and 

repair log and must be available on-site 

for inspection. Following return to 

operation from maintenance or repair 

activity, each device must pass a 

Method 22, 40 CFR part 60, Appendix 

A, visual observation as described in 

this paragraph. 

(2) Each vapor recovery device (e.g., 

carbon adsorption system or condenser) 

or other non-destructive control device 

must be designed and operated to 

reduce the mass content of VOC in the 

gases vented to the device by 95.0 

percent by weight or greater. A carbon 

replacement schedule must be included 

in the design of the carbon adsorption 

system. 

(3) You must operate each control 

device used to comply with this subpart 

at all times when gases, vapors, and 

fumes are vented from the storage vessel 

affected facility through the closed vent 

system to the control device. You may 

vent more than one affected facility to 

a control device used to comply with 

this subpart. 

■ 9. Section 60.5413 is amended by: 

■ a. Revising the introductory text; 

■ b. Revising paragraph (a)(7); 

■ c. Revising paragraph (d); and 

■ d. Adding paragraph (e). 

■ The revisions 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? 

This section applies to the 

performance testing of control devices 

used to demonstrate compliance with 

the emissions standards for your 

centrifugal compressor affected facility. 

You must demonstrate that a control 

device achieves the performance 

requirements of § 60.5412(a) using the 

performance test methods and 

procedures specified in this section. For 

condensers, you may use a design 

analysis as specified in paragraph (c) of 

this section in lieu of complying with 

paragraph (b) of this section. In 

addition, this section contains the 

requirements for enclosed combustion 

device performance tests conducted by 

the manufacturer applicable to both 

storage vessel and centrifugal 

compressor affected facilities. 

(a) * * * 

(7) A control device whose model can 

be demonstrated to meet the 

performance requirements of 

§ 60.5412(a) through a performance test 

conducted by the manufacturer, as 

specified in paragraph (d) of this 

section. 

* * * * * 

(d) Performance testing for 

combustion control devices— 

manufacturers’ performance test. (1) 

This paragraph applies to the 

performance testing of a combustion 

control device conducted by the device 

manufacturer. The manufacturer must 

demonstrate that a specific model of 

control device achieves the performance 

requirements in paragraph (d)(11) of this 

section by conducting a performance 

test as specified in paragraphs (d)(2) 

through (10) of this section. You must 

submit a test report for each combustion 

control device in accordance with the 

requirements in paragraph (d)(12) of this 

section. 

(2) Performance testing must consist 

of three one-hour (or longer) test runs 

for each of the four firing rate settings 

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

(iv) of this section, making a total of 12 

test runs per test. Propene (propylene) 

gas must be used for the testing fuel. All 

fuel analyses must be performed by an 

independent third-party laboratory (not 

affiliated with the control device 

manufacturer or fuel supplier). 

(i) 90–100 percent of maximum 

design rate (fixed rate). 

(ii) 70–100–70 percent (ramp up, 

ramp down). Begin the test at 70 percent 

of the maximum design rate. During the 

first 5 minutes, incrementally ramp the 

firing rate to 100 percent of the 

maximum design rate. Hold at 100 

percent for 5 minutes. In the 10–15 

minute time range, incrementally ramp 

back down to 70 percent of the 

maximum design rate. Repeat three 

more times for a total of 60 minutes of 

sampling. 

(iii) 30–70–30 percent (ramp up, ramp 

down). Begin the test at 30 percent of 

the maximum design rate. During the 

first 5 minutes, incrementally ramp the 

firing rate to 70 percent of the maximum 

design rate. Hold at 70 percent for 5 

minutes. In the 10–15 minute time 

range, incrementally ramp back down to 

30 percent of the maximum design rate. 

Repeat three more times for a total of 60 

minutes of sampling. 

(iv) 0–30–0 percent (ramp up, ramp 

down). Begin the test at the minimum 

firing rate. During the first 5 minutes, 

incrementally ramp the firing rate to 30 

percent of the maximum design rate. 

Hold at 30 percent for 5 minutes. In the 

10–15 minute time range, incrementally 

ramp back down to the minimum firing 

rate. Repeat three more times for a total 

of 60 minutes of sampling. 

(3) All models employing multiple 

enclosures must be tested 

simultaneously and with all burners 

operational. Results must be reported 

for each enclosure individually and for 

the average of the emissions from all 

interconnected combustion enclosures/ 

chambers. Control device operating data 

must be collected continuously 

throughout the performance test using 

an electronic Data Acquisition System. 

A graphic presentation or strip chart of 

the control device operating data and 

emissions test data must be included in 

the test report in accordance with 

paragraph (d)(12) of this section. Inlet 

fuel meter data may be manually 

recorded provided that all inlet fuel data 

readings are included in the final report. 

(4) Inlet testing must be conducted as 

specified in paragraphs (d)(4)(i) through 

(ii) of this section. 

(i) The inlet gas flow metering system 

must be located in accordance with 

Method 2A, 40 CFR part 60, appendix 

A–1, (or other approved procedure) to 

measure inlet gas flow rate at the control 

device inlet location. You must position 

the fitting for filling fuel sample 

containers a minimum of eight pipe 

diameters upstream of any inlet gas flow 

monitoring meter. 

(ii) Inlet flow rate must be determined 

using Method 2A, 40 CFR part 60, 

appendix A–1. Record the start and stop 

reading for each 60-minute THC test. 

Record the gas pressure and temperature 

at 5-minute intervals throughout each 

60-minute test. 

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(5) Inlet gas sampling must be 

conducted as specified in paragraphs 

(d)(5)(i) through (ii) of this section. 

(i) At the inlet gas sampling location, 

securely connect a Silonite-coated 

stainless steel evacuated canister fitted 

with a flow controller sufficient to fill 

the canister over a 3-hour period. Filling 

must be conducted as specified in 

paragraphs (d)(5)(i)(A) through (C) of 

this section. 

(A) Open the canister sampling valve 

at the beginning of each test run, and 

close the canister at the end of each test 

run. 

(B) Fill one canister across the three 

test runs such that one composite fuel 

sample exists for each test condition. 

(C) Label the canisters individually 

and record sample information on a 

chain of custody form. 

(ii) Analyze each inlet gas sample 

using the methods in paragraphs 

(d)(5)(ii)(A) through (C) of this section. 

You must include the results in the test 

report required by paragraph (d)(12) of 

this section. 

(A) Hydrocarbon compounds 

containing between one and five atoms 

of carbon plus benzene using ASTM 

D1945–03. 

(B) Hydrogen (H2), carbon monoxide 

(CO), carbon dioxide (CO2), nitrogen 

(N2), oxygen (O2) using ASTM D1945– 

03. 

(C) Higher heating value using ASTM 

D3588–98 or ASTM D4891 

89. 

(6) Outlet testing must be conducted 

in accordance with the criteria in 

paragraphs (d)(6)(i) through (v) of this 

section. 

(i) Sample and flow rate must be 

measured in accordance with 

paragraphs (d)(6)(i)(A) through (B) of 

this section. 

(A) The outlet sampling location must 

be a minimum of four equivalent stack 

diameters downstream from the highest 

peak flame or any other flow 

disturbance, and a minimum of one 

equivalent stack diameter upstream of 

the exit or any other flow disturbance. 

A minimum of two sample ports must 

be used. 

(B) Flow rate must be measured using 

Method 1, 40 CFR part 60, appendix A– 

1 for determining flow measurement 

traverse point location, and Method 2, 

40 CFR part 60, appendix A–1 for 

measuring duct velocity. If low flow 

conditions are encountered (i.e., 

velocity pressure differentials less than 

0.05 inches of water) during the 

performance test, a more sensitive 

manometer must be used to obtain an 

accurate flow profile. 

(ii) Molecular weight and excess air 

must be determined as specified in 

paragraph (d)(7) of this section. 

(iii) Carbon monoxide must be 

determined as specified in paragraph 

(d)(8) of this section. 

(iv) THC must be determined as 

specified in paragraph (d)(9) of this 

section. 

(v) Visible emissions must be 

determined as specified in paragraph 

(d)(10) of this section. 

(7) Molecular weight and excess air 

determination must be performed as 

specified in paragraphs (d)(7)(i) through 

(iii) of this section. 

(i) An integrated bag sample must be 

collected during the Method 4, 40 CFR 

part 60, appendix A–3, moisture test 

following the procedure specified in 

(d)(7)(i)(A) through (B) of this section. 

Analyze the bag sample using a gas 

chromatograph-thermal conductivity 

detector (GC–TCD) analysis meeting the 

criteria in paragraphs (d)(7)(i)(C) 

through (D) of this section. 

(A) Collect the integrated sample 

throughout the entire test, and collect 

representative volumes from each 

traverse location. 

(B) Purge the sampling line with stack 

gas before opening the valve and 

beginning to fill the bag. Clearly label 

each bag and record sample information 

on a chain of custody form. 

(C) The bag contents must be 

vigorously mixed prior to the gas 

chromatograph analysis. 

(D) The GC–TCD calibration 

procedure in Method 3C, 40 CFR part 

60, appendix A, must be modified by 

using EPA Alt–045 as follows: For the 

initial calibration, triplicate injections of 

any single concentration must agree 

within 5 percent of their mean to be 

valid. The calibration response factor for 

a single concentration re-check must be 

within 10 percent of the original 

calibration response factor for that 

concentration. If this criterion is not 

met, repeat the initial calibration using 

at least three concentration levels. 

(ii) Calculate and report the molecular 

weight of oxygen, carbon dioxide, 

methane, and nitrogen in the integrated 

bag sample and include in the test 

report specified in paragraph (d)(12) of 

this section. Moisture must be 

determined using Method 4, 40 CFR 

part 60, appendix A–3. Traverse both 

ports with the Method 4, 40 CFR part 

60, appendix A–3, sampling train 

during each test run. Ambient air must 

not be introduced into the Method 3C, 

40 CFR part 60, appendix A–2, 

integrated bag sample during the port 

change. 

(iii) Excess air must be determined 

using resultant data from the EPA 

Method 3C tests and EPA Method 3B, 40 

CFR part 60, appendix A, equation 

3B–1. 

(8) Carbon monoxide must be 

determined using Method 10, 40 CFR 

part 60, appendix A. Run the test 

simultaneously with Method 25A, 40 

CFR part 60, appendix A–7 using the 

same sampling points. An instrument 

range of 0–10 parts per million by 

volume-dry (ppmvd) is recommended. 

(9) Total hydrocarbon determination 

must be performed as specified by in 

paragraphs (d)(9)(i) through (vii) of this 

section. 

(i) Conduct THC sampling using 

Method 25A, 40 CFR part 60, appendix 

A–7, except that the option for locating 

the probe in the center 10 percent of the 

stack is not allowed. The THC probe 

must be traversed to 16.7 percent, 50 

percent, and 83.3 percent of the stack 

diameter during each test run. 

(ii) A valid test must consist of three 

Method 25A, 40 CFR part 60, appendix 

A–7, tests, each no less than 60 minutes 

in duration. 

(iii) A 0–10 parts per million by 

volume-wet (ppmvw) (as propane) 

measurement range is preferred; as an 

alternative a 0–30 ppmvw (as carbon) 

measurement range may be used. 

(iv) Calibration gases must be propane 

in air and be certified through EPA 

Protocol 1—‘‘EPA Traceability Protocol 

for Assay and Certification of Gaseous 

Calibration Standards,’’ September 

1997, as amended August 25, 1999, 

EPA–600/R–97/121(or more recent if 

updated since 1999). 

(v) THC measurements must be 

reported in terms of ppmvw as propane. 

(vi) THC results must be corrected to 

3 percent CO2, as measured by Method 

3C, 40 CFR part 60, appendix A–2. You 

must use the following equation for this 

diluent concentration correction: 

Where: 

Cmeas = The measured concentration of the 

pollutant. 

CO2meas = The measured concentration of the 

CO2 diluent. 

3 = The corrected reference concentration of 

CO2 diluent. 

Ccorr = The corrected concentration of the 

pollutant. 

(vii) Subtraction of methane or ethane 

from the THC data is not allowed in 

determining results. 

(10) Visible emissions must be 

determined using Method 22, 40 CFR 

part 60, appendix A. The test must be 

performed continuously during each 

test run. A digital color photograph of 

the exhaust point, taken from the 


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position of the observer and annotated 

with date and time, must be taken once 

per test run and the 12 photos included 

in the test report specified in paragraph 

(d)(12) of this section. 

(11) Performance test criteria. (i) The 

control device model tested must meet 

the criteria in paragraphs (d)(11)(i)(A) 

through (D) of this section. These 

criteria must be reported in the test 

report required by paragraph (d)(12) of 

this section. 

(A) Method 22, 40 CFR part 60, 

appendix A, results under paragraph 

(d)(10) of this section with no indication 

of visible emissions. 

(B) Average Method 25A, 40 CFR part 

60, appendix A, results under paragraph 

(d)(9) of this section equal to or less 

than 10.0 ppmvw THC as propane 

corrected to 3.0 percent CO2. 

(C) Average CO emissions determined 

under paragraph (d)(8) of this section 

equal to or less than 10 parts ppmvd, 

corrected to 3.0 percent CO2. 

(D) Excess combustion air determined 

under paragraph (d)(7) of this section 

equal to or greater than 150 percent. 

(ii) The manufacturer must determine 

a maximum inlet gas flow rate which 

must not be exceeded for each control 

device model to achieve the criteria in 

paragraph (d)(11)(iii) of this section. The 

maximum inlet gas flow rate must be 

included in the test report required by 

paragraph (d)(12) of this section. 

(iii) A control device meeting the 

criteria in paragraph (d)(11)(i)(A) 

through (D) of this section must 

demonstrate a destruction efficiency of 

95 percent for VOC regulated under this 

subpart. 

(12) The owner or operator of a 

combustion control device model tested 

under this section must submit the 

information listed in paragraphs 

(d)(12)(i) through (vi) in the test report 

required by this section. 

(i) A full schematic of the control 

device and dimensions of the device 

components. 

(ii) The maximum net heating value of 

the device. 

(iii) The test fuel gas flow range (in 

both mass and volume). Include the 

maximum allowable inlet gas flow rate. 

(iv) The air/stream injection/assist 

ranges, if used. 

(v) The test conditions listed in 

paragraphs (d)(12)(v)(A) through (O) of 

this section, as applicable for the tested 

model. 

(A) Fuel gas delivery pressure and 

temperature. 

(B) Fuel gas moisture range. 

(C) Purge gas usage range. 

(D) Condensate (liquid fuel) 

separation range. 

(E) Combustion zone temperature 

range. This is required for all devices 

that measure this parameter. 

(F) Excess combustion air range. 

(G) Flame arrestor(s). 

(H) Burner manifold. 

(I) Pilot flame indicator. 

(J) Pilot flame design fuel and 

calculated or measured fuel usage. 

(K) Tip velocity range. 

(L) Momentum flux ratio. 

(M) Exit temperature range. 

(N) Exit flow rate. 

(O) Wind velocity and direction. 

(vi) The test report must include all 

calibration quality assurance/quality 

control data, calibration gas values, gas 

cylinder certification, strip charts, or 

other graphic presentations of the data 

annotated with test times and 

calibration values. 

(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 (6) of this 

section. 

(1) The inlet gas flow rate must be 

equal to or less than the maximum 

specified by the manufacturer. 

(2) A pilot flame must be present at 

all times of operation. 

(3) Devices must be operated with no 

visible emissions, except for periods not 

to exceed a total of 2 minutes during 

any hour. A visible emissions test using 

Method 22, 40 CFR part 60, appendix A, 

must be performed each calendar 

quarter. The observation period must be 

1 hour and must be conducted 

according to EPA Method 22, 40 CFR 

part 60, appendix A. 

(4) Devices failing the visible 

emissions test must follow 

manufacturer’s repair instructions, if 

available, or best combustion 

engineering practice as outlined in the 

unit inspection and maintenance plan, 

to return the unit to compliant 

operation. All repairs and maintenance 

activities for each unit must be recorded 

in a maintenance and repair log and 

must be available on site for inspection. 

(5) Following return to operation from 

maintenance or repair activity, each 

device must pass an EPA Method 22, 40 

CFR part 60, Appendix A, visual 

observation as described in paragraph 

(e)(3) of this section. 

(6) If the owner or operator operates 

a combustion control device model 

tested under this section, an electronic 

copy of the performance test results 

required by this section shall be 

submitted via email to 

Oil_and_Gas_PT@EPA.GOV unless the 

test results for that model of combustion 

control device are posted at the 

following Web site: epa.gov/airquality/ 

oilandgas/. 

■ 10. Section 60.5415 is amended by: 

■ a. Revising paragraph (b) introductory 

text; 

■ b. Revising paragraph (b)(2); 

■ c. Revising paragraph (e) introductory 

text; 

■ d. Removing and reserving paragraphs 

(e)(1) and (2); 

■ e. Adding paragraph (e)(3); and 

■ f. Revising paragraph (h)(1) 

introductory text. 

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) For each centrifugal compressor 

affected facility, you must demonstrate 

continuous compliance according to 

paragraph (b)(1) through (3) of this 

section. 

* * * * * 

(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. 

(i) You must operate below (or above) 

the site specific maximum (or 

minimum) parameter value established 

according to the requirements of 

§ 60.5417(f)(1). 

(ii) You must calculate the daily 

average of the applicable monitored 

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parameter in accordance with 

§ 60.5417(e) except that the inlet gas 

flow rate to the control device must not 

be averaged. 

(iii) Compliance with the operating 

parameter limit is achieved when the 

daily average of the monitoring 

parameter value calculated under 

paragraph (b)(2)(ii) of this section is 

either equal to or greater than the 

minimum monitoring value or equal to 

or less than the maximum monitoring 

value established under paragraph 

(b)(2)(i) of this section. When 

performance testing of a combustion 

control device is conducted by the 

device manufacturer as specified in 

§ 60.5413(d), compliance with the 

operating parameter limit is achieved 

when the criteria in § 60.5413(e) are 

met. 

(iv) You must operate the continuous 

monitoring system required in § 60.5417 

at all times the affected source is 

operating, except for periods of 

monitoring system malfunctions, repairs 

associated with monitoring system 

malfunctions, and required monitoring 

system quality assurance or quality 

control activities (including, as 

applicable, system accuracy audits and 

required zero and span adjustments). A 

monitoring system malfunction is any 

sudden, infrequent, not reasonably 

preventable failure of the monitoring 

system to provide valid data. 

Monitoring system failures that are 

caused in part by poor maintenance or 

careless operation are not malfunctions. 

You are required to complete 

monitoring system repairs in response 

to monitoring system malfunctions and 

to return the monitoring system to 

operation as expeditiously as 

practicable. 

(v) You may not use data recorded 

during monitoring system malfunctions, 

repairs associated with monitoring 

system malfunctions, or required 

monitoring system quality assurance or 

control activities in calculations used to 

report emissions or operating levels. 

You must use all the data collected 

during all other required data collection 

periods to assess the operation of the 

control device and associated control 

system. 

(vi) Failure to collect required data is 

a deviation of the monitoring 

requirements, except for periods of 

monitoring system malfunctions, repairs 

associated with monitoring system 

malfunctions, and required quality 

monitoring system quality assurance or 

quality control activities (including, as 

applicable, system accuracy audits and 

required zero and span adjustments). 

(vii) If you use a combustion control 

device to meet the requirements of 

§ 60.5412(a) and you demonstrate 

compliance using the test procedures 

specified in § 60.5413(b), you must 

comply with paragraphs (b)(2)(vii)(A) 

through (D) of this section. 

(A) A pilot flame must be present at 

all times of operation. 

(B) Devices must be operated with no 

visible emissions, except for periods not 

to exceed a total of 2 minutes during 

any hour. A visible emissions test using 

Method 22, 40 CFR part 60, appendix A, 

must be performed each calendar 

quarter. The observation period must be 

1 hour and must be conducted 

according to EPA Method 22, 40 CFR 

part 60, appendix A. 

(C) Devices failing the visible 

emissions test must follow 

manufacturer’s repair instructions, if 

available, or best combustion 

engineering practice as outlined in the 

unit inspection and maintenance plan, 

to return the unit to compliant 

operation. All repairs and maintenance 

activities for each unit must be recorded 

in a maintenance and repair log and 

must be available on site for inspection. 

(D) Following return to operation 

from maintenance or repair activity, 

each device must pass a Method 22, 40 

CFR part 60, Appendix A, visual 

observation as described in paragraph 

(b)(2)(vii)(B) of this section. 

(viii) If you use a condenser as the 

control device to achieve the percent 

reduction performance requirements 

specified in § 60.5412(a)(2), you must 

demonstrate compliance using the 

procedures in paragraphs (b)(2)(viii)(A) 

through (E) of this section. 

(A) You must establish a site-specific 

condenser performance curve according 

to § 60.5417(f)(2). 

(B) You must calculate the daily 

average condenser outlet temperature in 

accordance with § 60.5417(e). 

(C) You must determine the 

condenser efficiency for the current 

operating day using the daily average 

condenser outlet temperature calculated 

under paragraph (b)(2)(viii)(B) of this 

section and the condenser performance 

curve established under paragraph 

(b)(2)(viii)(A) of this section. 

(D) Except as provided in paragraphs 

(b)(2)(viii)(D)(1) and (2) of this section, 

at the end of each operating day, you 

must calculate the 365-day rolling 

average TOC emission reduction, as 

appropriate, from the condenser 

efficiencies as determined in paragraph 

(b)(2)(viii)(C) of this section. 

(1) After the compliance dates 

specified in § 60.5370, if you have less 

than 120 days of data for determining 

average TOC emission reduction, you 

must calculate the average TOC 

emission reduction for the first 120 days 

of operation after the compliance dates. 

You have demonstrated compliance 

with the overall 95.0 percent reduction 

requirement if the 120-day average TOC 

emission reduction is equal to or greater 

than 95.0 percent. 

(2) After 120 days and no more than 

364 days of operation after the 

compliance date specified in § 60.5370, 

you must calculate the average TOC 

emission reduction as the TOC emission 

reduction averaged over the number of 

days between the current day and the 

applicable compliance date. You have 

demonstrated compliance with the 

overall 95.0 percent reduction 

requirement, if the average TOC 

emission reduction is equal to or greater 

than 95.0 percent. 

(E) If you have data for 365 days or 

more of operation, you have 

demonstrated compliance with the TOC 

emission reduction if the rolling 365- 

day average TOC emission reduction 

calculated in paragraph (b)(2)(viii)(D) of 

this section is equal to or greater than 

95.0 percent. 

* * * * * 

(e) You must demonstrate continuous 

compliance according to paragraph 

(e)(3) of this section for each storage 

vessel affected facility, for which you 

are using a control device or routing 

emissions to a flow line to meet the 

requirement of § 60.5395(d)(1). 

(1) [Reserved] 

(2) [Reserved] 

(3) For each storage vessel affected 

facility subject to § 60.5395(d)(1), you 

must comply with paragraphs (e)(3)(i) 

and (ii) of this section. 

(i) You must reduce VOC emissions 

by 95.0 percent or greater. 

(ii) You must demonstrate continuous 

compliance with the performance 

requirements of § 60.5412(d) for each 

storage vessel affected facility using the 

procedure specified in paragraph 

(e)(3)(ii)(A) and either (e)(3)(ii)(B) or 

(e)(3)(ii)(C) of this section. 

(A) You must comply with 

§ 60.5416(c) for each cover and closed 

vent system. 

(B) You must comply with 

§ 60.5417(h) for each control device. 

(C) Each closed vent system that 

routes emissions to a flow line, as 

defined in § 60.5430, must be 

operational 95 percent of the year or 

greater. 

* * * * * 

(h) * * * 

(1) To establish the affirmative 

defense in any action to enforce such a 

standard, you must timely meet the 

reporting requirements in 

§ 60.5415(h)(2), and must prove by a 

preponderance of evidence that: 

* * * * * 

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■ 11. Section 60.5416 is amended by: 

■ a. Revising the introductory text; 

■ b. Revising paragraph (a) introductory 

text; 

■ c. Revising paragraph (a)(1)(ii); 

■ d. Revising paragraph (a)(2)(iii); 

■ e. Revising paragraph (a)(3)(ii); 

■ f. Revising paragraph (b) introductory 

text, 

■ g. Revising paragraph (b)(9) 

introductory text; 

■ h. Revising paragraph (b)(11); and 

■ i. Adding paragraph (c). 

The revisions and addition read as 

follows: 

§ 60.5416 What are the initial and 

continuous cover and closed vent system 

inspection and monitoring requirements for 

my storage vessel and centrifugal 

compressor affected facility? 

For each closed vent system or cover 

at your storage vessel or centrifugal 

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 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. 

(1) * * * 

(ii) Conduct annual visual inspections 

for defects that could result in air 

emissions. Defects include, but are not 

limited to, visible cracks, holes, or gaps 

in piping; loose connections; liquid 

leaks; or broken or missing caps or other 

closure devices. You must monitor a 

component or connection using the test 

methods and procedures in paragraph 

(b) of this section to demonstrate that it 

operates with no detectable emissions 

following any time the component is 

repaired or replaced or the connection 

is unsealed. You must maintain records 

of the inspection results as specified in 

§ 60.5420(c)(6). 

(2) * * * 

(iii) Conduct annual visual 

inspections for defects that could result 

in air emissions. Defects include, but are 

not limited to, visible cracks, holes, or 

gaps in ductwork; loose connections; 

liquid leaks; or broken or missing caps 

or other closure devices. You must 

maintain records of the inspection 

results as specified in § 60.5420(c)(6). 

(3) * * * 

(ii) You must initially conduct the 

inspections specified in paragraph 

(a)(3)(i) of this section following the 

installation of the cover. Thereafter, you 

must perform the inspection at least 

once every calendar year, except as 

provided in paragraphs (b)(11) and (12) 

of this section. You must maintain 

records of the inspection results as 

specified in § 60.5420(c)(7). 

* * * * * 

(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 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. 

* * * * * 

(9) Repairs. In the event that a leak or 

defect is detected, you must repair the 

leak or defect as soon as practicable 

according to the requirements of 

paragraphs (b)(9)(i) and (ii) of this 

section, except as provided in paragraph 

(b)(10) of this section. 

* * * * * 

(11) Unsafe to inspect requirements. 

You may designate any parts of the 

closed vent system or cover as unsafe to 

inspect if the requirements in 

paragraphs (b)(11)(i) and (ii) of this 

section are met. Unsafe to inspect parts 

are exempt from the inspection 

requirements of paragraphs (a)(1) 

through (3) of this section. 

(i) You determine that the equipment 

is unsafe to inspect because inspecting 

personnel would be exposed to an 

imminent or potential danger as a 

consequence of complying with 

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

section. 

(ii) You have a written plan that 

requires inspection of the equipment as 

frequently as practicable during safe-toinspect times. 

* * * * * 

(c) Cover and closed vent system 

inspections for storage vessel affected 

facilities. If you install a control device 

or route emissions to a flow line, you 

must inspect each closed vent system 

according to the procedures and 

schedule specified in paragraphs (c)(1) 

of this section, inspect each cover 

according to the procedures and 

schedule specified in paragraph (c)(2) of 

this section, and inspect each bypass 

device according to the procedures of 

paragraph (c)(3) of this section. You 

must also comply with the requirements 

of (c)(4) through (8) of this section. 

(1) For each closed vent system, you 

must conduct an inspection at least 

once every calendar month as specified 

in paragraphs (c)(1)(i) through (iii) of 

this section. 

(i) You must maintain records of the 

inspection results as specified in 

§ 60.5420(c)(6). 

(ii) Conduct olfactory, visual and 

auditory inspections for defects that 

could result in air emissions. Defects 

include, but are not limited to, visible 

cracks, holes, or gaps in piping; loose 

connections; liquid leaks; or broken or 

missing caps or other closure devices. 

(iii) Monthly inspections must be 

separated by at least 14 calendar days. 

(2) For each cover, you must conduct 

inspections at least once every calendar 

month as specified in paragraphs 

(c)(2)(i) through (iii) of this section. 

(i) You must maintain records of the 

inspection results as specified in 

§ 60.5420(c)(7). 

(ii) Conduct olfactory, visual and 

auditory inspections for defects that 

could result in air emissions. Defects 

include, but are not limited to, visible 

cracks, holes, or gaps in the cover, or 

between the cover and the separator 

wall; broken, cracked, or otherwise 

damaged seals or gaskets on closure 

devices; and broken or missing hatches, 

access covers, caps, or other closure 

devices. In the case where the storage 

vessel is buried partially or entirely 

underground, you must inspect only 

those portions of the cover that extend 

to or above the ground surface, and 

those connections that are on such 

portions of the cover (e.g., fill ports, 

access hatches, gauge wells, etc.) and 

can be opened to the atmosphere. 

(iii) Monthly inspections must be 

separated by at least 14 calendar days. 

(3) For each bypass device, except as 

provided for in § 60.5411, you must 

meet the requirements of paragraphs 

(c)(3)(i) or (ii) of this section. 

(i) Set the flow indicator to sound an 

alarm at the inlet to the bypass device 

when the stream is being diverted away 

from the control device to the 

atmosphere. 

(ii) If the bypass device valve installed 

at the inlet to the bypass device is 

secured in the non-diverting position 

using a car-seal or a lock-and-key type 

configuration, visually inspect the seal 

or closure mechanism at least once 

every month to verify that the valve is 

maintained in the non-diverting 

position and the vent stream is not 

diverted through the bypass device. You 

must maintain records of the 

inspections according to § 60.5420(c)(8). 

(4) Repairs. In the event that a leak or 

defect is detected, you must repair the 

leak or defect as soon as practicable 

according to the requirements of 

paragraphs (c)(4)(i) through (iii) of this 

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section, except as provided in paragraph 

(c)(5) of this section. 

(i) A first attempt at repair must be 

made no later than 5 calendar days after 

the leak is detected. 

(ii) Repair must be completed no later 

than 30 calendar days after the leak is 

detected. 

(iii) Grease or another applicable 

substance must be applied to 

deteriorating or cracked gaskets to 

improve the seal while awaiting repair. 

(5) Delay of repair. Delay of repair of 

a closed vent system or cover for which 

leaks or defects have been detected is 

allowed if the repair is technically 

infeasible without a shutdown, or if you 

determine that emissions resulting from 

immediate repair would be greater than 

the fugitive emissions likely to result 

from delay of repair. You must complete 

repair of such equipment by the end of 

the next shutdown. 

(6) Unsafe to inspect requirements. 

You may designate any parts of the 

closed vent system or cover as unsafe to 

inspect if the requirements in 

paragraphs (c)(6)(i) and (ii) of this 

section are met. Unsafe to inspect parts 

are exempt from the inspection 

requirements of paragraphs (c)(1) and 

(2) of this section. 

(i) You determine that the equipment 

is unsafe to inspect because inspecting 

personnel would be exposed to an 

imminent or potential danger as a 

consequence of complying with 

paragraphs (c)(1) or (2) of this section. 

(ii) You have a written plan that 

requires inspection of the equipment as 

frequently as practicable during safe-toinspect times. 

(7) Difficult to inspect requirements. 

You may designate any parts of the 

closed vent system or cover as difficult 

to inspect, if the requirements in 

paragraphs (c)(7)(i) and (ii) of this 

section are met. Difficult to inspect parts 

are exempt from the inspection 

requirements of paragraphs (c)(1) and 

(2) of this section. 

(i) You determine that the equipment 

cannot be inspected without elevating 

the inspecting personnel more than 2 

meters above a support surface. 

(ii) You have a written plan that 

requires inspection of the equipment at 

least once every 5 years. 

(8) Records. Records shall be 

maintained as specified in this section 

and in § 60.5420(c)(12). 

■ 12. Section 60.5417 is amended by: 

■ a. Revising paragraph (a); 

■ b. Revising paragraph (b) introductory 

text; 

■ c. Revising paragraph (c) introductory 

text; 

■ d. Revising paragraphs (d)(1)(viii)(A) 

and (B); 

■ e. Revising paragraph (d)(2); 

■ f. Revising paragraph (f)(1)(iii); 

■ g. Revising paragraph (g)(6)(ii); and 

■ h. Adding paragraph (h). 

The revisions and addition read as 

follows: 

§ 60.5417 What are the continuous control 

device monitoring requirements for my 

storage vessel or centrifugal compressor 

affected facility? 

* * * * * 

(a) For each control device used to 

comply with the emission reduction 

standard for centrifugal compressor 

affected facilities in § 60.5380, you must 

install and operate a continuous 

parameter monitoring system for each 

control device as specified in 

paragraphs (c) through (g) of this 

section, except as provided for in 

paragraph (b) of this section. If you 

install and operate a flare in accordance 

with § 60.5412(a)(3), you are exempt 

from the requirements of paragraphs (e) 

and (f) of this section. 

(b) You are exempt from the 

monitoring requirements specified in 

paragraphs (c) through (g) of this section 

for the control devices listed in 

paragraphs (b)(1) and (2) of this section. 

* * * * * 

(c) If you are required to install a 

continuous parameter monitoring 

system, you must meet the 

specifications and requirements in 

paragraphs (c)(1) through (4) of this 

section. 

* * * * * 

(d) * * * 

(1) * * * 

(viii) * * * 

(A) The continuous monitoring 

system must measure gas flow rate at 

the inlet to the control device. The 

monitoring instrument must have an 

accuracy of ±2 percent or better. The 

flow rate at the inlet to the combustion 

device must not exceed the maximum or 

minimum flow rate determined by the 

manufacturer. 

(B) A monitoring device that 

continuously indicates the presence of 

the pilot flame while emissions are 

routed to the control device. 

(2) An organic monitoring device 

equipped with a continuous recorder 

that measures the concentration level of 

organic compounds in the exhaust vent 

stream from the control device. The 

monitor must meet the requirements of 

Performance Specification 8 or 9 of 40 

CFR part 60, appendix B. You must 

install, calibrate, and maintain the 

monitor according to the manufacturer’s 

specifications. 

* * * * * 

(f) * * * 

(1) * * * 

(iii) If you operate a control device 

where the performance test requirement 

was met under § 60.5413(d) to 

demonstrate that the control device 

achieves the applicable performance 

requirements specified in § 60.5412(a), 

then your control device inlet gas flow 

rate must not exceed the maximum or 

minimum inlet gas flow rate determined 

by the manufacturer. 

* * * * * 

(g) * * * 

(6) * * * 

(ii) Failure of the quarterly visible 

emissions test conducted under 

§ 60.5413(e)(3) occurs. 

(h) For each control device used to 

comply with the emission reduction 

standard in § 60.5395(d)(1) for your 

storage vessel affected facility, you must 

demonstrate continuous compliance 

according to paragraphs (h)(1) through 

(h)(3) of this section. You are exempt 

from the requirements of this paragraph 

if you install a control device model 

tested in accordance with 

§ 60.5413(d)(2) through (10), which 

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

the reporting requirement in 

§ 60.5413(d)(12), and meet the 

continuous compliance requirement in 

§ 60.5413(e). 

(1) For each combustion device you 

must conduct inspections at least once 

every calendar month according to 

paragraphs (h)(1)(i) through (iv) of this 

section. Monthly inspections must be 

separated by at least 14 calendar days. 

(i) Conduct visual inspections to 

confirm that the pilot is lit when vapors 

are being routed to the combustion 

device and that the continuous burning 

pilot flame is operating properly. 

(ii) Conduct inspections to monitor 

for visible emissions from the 

combustion device using section 11 of 

EPA Method 22, 40 CFR part 60, 

Appendix A. The observation period 

shall be 15 minutes. Devices must be 

operated with no visible emissions, 

except for periods not to exceed a total 

of 1 minute during any 15 minute 

period. 

(iii) Conduct olfactory, visual and 

auditory inspections of all equipment 

associated with the combustion device 

to ensure system integrity. 

(iv) For any absence of pilot flame, or 

other indication of smoking or improper 

equipment operation (e.g., visual, 

audible, or olfactory), you must ensure 

the equipment is returned to proper 

operation as soon as practicable after the 

event occurs. At a minimum, you must 

perform the procedures specified in 

paragraphs (h)(1)(iv)(A) and (B) of this 

section. 

(A) You must check the air vent for 

obstruction. If an obstruction is 

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observed, you must clear the obstruction 

as soon as practicable. 

(B) You must check for liquid 

reaching combustor. 

(2) For each vapor recovery device, 

you must conduct inspections at least 

once every calendar month to ensure 

physical integrity of the control device 

according to the manufacturer’s 

instructions. Monthly inspections must 

be separated by at least 14 calendar 

days. 

(3) Each control device must be 

operated following the manufacturer’s 

written operating instructions, 

procedures and maintenance schedule 

to ensure good air pollution control 

practices for minimizing emissions. 

Records of the manufacturer’s written 

operating instructions, procedures, and 

maintenance schedule must be 

maintained onsite as specified in 

§ 60.5420(c)(14). 

■ 13. Section 60.5420 is amended by: 

■ a. Revising paragraph (a) introductory 

text; 

■ b. Revising paragraph (a)(1); 

■ c. Adding paragraph (a)(3); 

■ d. Revising paragraph (b) introductory 

text; 

■ e. Revising paragraph (b)(3)(iii); 

■ f. Revising paragraph (b)(5) 

introductory text; 

■ g. Revising paragraph (b)(5)(i); 

■ h. Revising paragraphs (b)(6)(i) and 

(ii); 

■ i. Revising paragraphs (b)(7)(i) and (ii); 

■ j. Adding paragraph (b)(8); 

■ k. Revising paragraph (c) introductory 

text; 

■ l. Revising paragraph (c)(1)(v); 

■ m. Revising paragraph (c)(5) 

introductory text; 

■ n. Revising paragraph (c)(5)(ii); 

■ o. Adding paragraph (c)(5)(v); 

■ p. Revising paragraphs (c)(6) through 

(11); and 

■ q. Adding paragraphs (c)(12) through 

(14). 

The revisions and additions read as 

follows: 

§ 60.5420 What are my notification, 

reporting, and recordkeeping 

requirements? 

(a) You must submit the notifications 

according to paragraphs (a)(1) through 

(3) of this section if you own or operate 

one or more of the affected facilities 

specified in § 60.5365 that was 

constructed, modified, or reconstructed 

during the reporting period. 

(1) If you own or operate a gas well, 

pneumatic controller, centrifugal 

compressor, reciprocating compressor or 

storage vessel affected facility you are 

not required to submit the notifications 

required in § 60.7(a)(1), (3), and (4). 

* * * * * 

(3) You must submit a notification 

identifying each Group 1 storage vessel 

by October 15, 2013. The notification 

must contain the location of the storage 

vessel, in latitude and longitude 

coordinates in decimal degrees to an 

accuracy and precision of five (5) 

decimals of a degree using the North 

American Datum of 1983. 

(b) Reporting requirements. You must 

submit annual reports containing the 

information specified in paragraphs 

(b)(1) through (6) of this section to the 

Administrator and performance test 

reports as specified in paragraph (b)(7) 

or (8) of this section. The initial annual 

report is due no later than 90 days after 

the end of the initial compliance period 

as determined according to § 60.5410. 

Subsequent annual reports are due no 

later than same date each year as the 

initial annual report. If you own or 

operate more than one affected facility, 

you may submit one report for multiple 

affected facilities provided the report 

contains all of the information required 

as specified in paragraphs (b)(1) through 

(6) of this section. Annual reports may 

coincide with title V reports as long as 

all the required elements of the annual 

report are included. You may arrange 

with the Administrator a common 

schedule on which reports required by 

this part may be submitted as long as 

the schedule does not extend the 

reporting period. 

* * * * * 

(3) * * * 

(iii) If required to comply with 

§ 60.5380(a)(1), the records specified in 

paragraphs (c)(6) through (14) of this 

section. 

* * * * * 

(5) For each pneumatic controller 

affected facility, the information 

specified in paragraphs (b)(5)(i) through 

(iii) of this section. 

(i) An identification of each 

pneumatic controller constructed, 

modified or reconstructed during the 

reporting period, including the 

identification information specified in 

§ 60.5390(b)(2) or § 60.5390(c)(2). 

* * * * * 

(6) * * * 

(i) An identification, including the 

location, of each storage vessel affected 

facility constructed, modified or 

reconstructed during the reporting 

period. The location of the storage 

vessel shall be in latitude and longitude 

coordinates in decimal degrees to an 

accuracy and precision of five (5) 

decimals of a degree using the North 

American Datum of 1983. 

(ii) Documentation of the VOC 

emission rate determination according 

to the requirements in § 60.5395(b) or (c) 

or as required in § 60.5395(d)(2). 

* * * * * 

(7) (i) Within 60 days after the date of 

completing each performance test (see 

§ 60.8 of this part) as required by this 

subpart, except testing conducted by the 

manufacturer as specified in 

§ 60.5413(d), you must submit the 

results of the performance tests required 

by this subpart to the EPA as follows. 

You must use the latest version of the 

EPA’s Electronic Reporting Tool (ERT) 

(see http://www.epa.gov/ttn/chief/ert/ 

index.html) existing at the time of the 

performance test to generate a 

submission package file, which 

documents the performance test. You 

must then submit the file generated by 

the ERT through the EPA’s Compliance 

and Emissions Data Reporting Interface 

(CEDRI), which can be accessed by 

logging in to the EPA’s Central Data 

Exchange (CDX) (https://cdx.epa.gov/). 

Only data collected using test methods 

supported by the ERT as listed on the 

ERT Web site are subject to this 

requirement for submitting reports 

electronically. Owners or operators who 

claim that some of the information being 

submitted for performance tests is 

confidential business information (CBI) 

must submit a complete ERT file 

including information claimed to be CBI 

on a compact disk or other commonly 

used electronic storage media 

(including, but not limited to, flash 

drives) to EPA. The electronic media 

must be clearly marked as CBI and 

mailed to U.S. EPA/OAQPS/CORE CBI 

Office, Attention: WebFIRE 

Administrator, MD C404–02, 4930 Old 

Page Rd., Durham, NC 27703. The same 

ERT file with the CBI omitted must be 

submitted to EPA via CDX as described 

earlier in this paragraph. At the 

discretion of the delegated authority, 

you must also submit these reports, 

including the confidential business 

information, to the delegated authority 

in the format specified by the delegated 

authority. For any performance test 

conducted using test methods that are 

not listed on the ERT Web site, the 

owner or operator shall submit the 

results of the performance test to the 

Administrator at the appropriate 

address listed in § 60.4. 

(ii) All reports, except as specified in 

paragraph (b)(8) of this section, required 

by this subpart not subject to the 

requirements in paragraph (a)(2)(i) of 

this section must be sent to the 

Administrator at the appropriate 

address listed in § 60.4 of this part. The 

Administrator or the delegated authority 

may request a report in any form 

suitable for the specific case (e.g., by 

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commonly used electronic media such 

as Excel spreadsheet, on CD or hard 

copy). 

(8) For enclosed combustors tested by 

the manufacturer in accordance with 

§ 60.5413(d), an electronic copy of the 

performance test results required by 

§ 60.5413(d) shall be submitted via 

email to Oil_and_Gas_PT@EPA.GOV 

unless the test results for that model of 

combustion control device are posted at 

the following Web site: epa.gov/ 

airquality/oilandgas/. 

(c) Recordkeeping requirements. You 

must maintain the records identified as 

specified in § 60.7(f) and in paragraphs 

(c)(1) through (14) of this section. All 

records must be maintained for at least 

5 years. 

(1) * * * 

(v) For each gas well affected facility 

required to comply with both 

§ 60.5375(a)(1) and (3), if you are using 

a digital photograph in lieu of the 

records required in paragraphs (c)(1)(i) 

through (iv) of this section, you must 

retain the records of the digital 

photograph as specified in 

§ 60.5410(a)(4). 

* * * * * 

(5) Except as specified in paragraph 

(c)(5)(v) of this section, for each storage 

vessel affected facility, you must 

maintain the records identified in 

paragraphs (c)(5)(i) through (iv) of this 

section. 

* * * * * 

(ii) Records of each VOC emissions 

determination for each storage vessel 

affected facility required under 

§ 60.5395(b), (c) and (d)(2), as 

applicable, including identification of 

the model or calculation methodology 

used to calculate the VOC emission rate. 

* * * * * 

(v) You must maintain records of the 

identification and location of each 

Group 1 storage vessel. If you have an 

event, as specified in § 60.5395(b)(2), 

that could reasonably be expected to 

increase VOC emissions from your 

Group 1 storage vessel, you must 

maintain records of the VOC emissions 

rate determination. 

(6) Records of each closed vent system 

inspection required under 

§ 60.5416(a)(1) for centrifugal 

compressors or § 60.5416(c)(1) for 

storage vessels. 

(7) A record of each cover inspection 

required under § 60.5416(a)(3) for 

centrifugal 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 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) For each closed vent system used 

to comply with this subpart that must 

operate with no detectable emissions, a 

record of the monitoring conducted in 

accordance with § 60.5416(b). 

(10) For each centrifugal compressor 

affected facility, records of the schedule 

for carbon replacement (as determined 

by the design analysis requirements of 

§ 60.5413(c)(2) or (3)) and records of 

each carbon replacement as specified in 

§ 60.5412(c)(1). 

(11) For each centrifugal compressor 

subject to the control device 

requirements of § 60.5412(a), (b), and 

(c), records of minimum and maximum 

operating parameter values, continuous 

parameter monitoring system data, 

calculated averages of continuous 

parameter monitoring system data, 

results of all compliance calculations, 

and results of all inspections. 

(12) For each cover and closed vent 

system installed on storage vessel 

affected facilities used to comply with 

§ 60.5416(c), a record of all inspections. 

(13) For each carbon adsorber 

installed on storage vessel affected 

facilities, records of the schedule for 

carbon replacement (as determined by 

the design analysis requirements of 

§ 60.5412(d)(2)) and records of each 

carbon replacement as specified in 

§ 60.5412(c)(1). 

(14) For each storage vessel affected 

facility subject to the control device 

requirements of § 60.5412(c) and (d), 

you must maintain records of the 

inspections, including any corrective 

actions taken, the manufacturers’ 

operating instructions, procedures and 

maintenance schedule as specified in 

§ 60.5417(h). You must maintain records 

of EPA Method 22, 40 CFR part 60, 

Appendix A, section 11 results, which 

include: company, location, company 

representative (name of the person 

performing the observation), sky 

conditions, process unit (type of control 

device), clock start time, observation 

period duration (in minutes and 

seconds), accumulated emission time 

(in minutes and seconds), and clock end 

time. You may create your own form 

including the above information or use 

Figure 22–1 in EPA Method 22, 40 CFR 

part 60, Appendix A. Manufacturer’s 

records must be maintained onsite. 

■ 14. Section 60.5430 is amended by: 

■ a. Adding, in alphabetical order, 

definitions for the terms ‘‘condensate,’’ 

‘‘Group 1 storage vessel,’’ ‘‘Group 2 

storage vessel,’’ ‘‘intermediate 

hydrocarbon liquid’’ and ‘‘produced 

water;’’ and 

■ b. Revising the definition for ‘‘storage 

vessel’’ to read as follows: 

§ 60.5430 What definitions apply to this 

subpart? 

* * * * * 

Condensate means hydrocarbon 

liquid separated from natural gas that 

condenses due to changes in the 

temperature, pressure, or both, and 

remains liquid at standard conditions. 

* * * * * 

Group 1 storage vessel means a 

storage vessel, as defined in this section, 

that is constructed, modified or 

reconstructed on or after August 23, 

2011, and before April 12, 2013. 

Group 2 storage vessel means a 

storage vessel, as defined in this section, 

that is constructed, modified or 

reconstructed on or after April 12, 2013. 

* * * * * 

Intermediate hydrocarbon liquid 

means any naturally occurring, 

unrefined petroleum liquid. 

* * * * * 

Produced water means water that is 

extracted from the earth from an oil or 

natural gas production well, or that is 

separated from crude oil, condensate, or 

natural gas after extraction. 

* * * * * 

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. 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 since the original 

vessel was first located at the site. 

(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. 

* * * * * 

■ 15. Appendix to subpart OOOO of 

part 60 is amended by revising Tables 

1 and 2 to read as follows: 

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TABLE 1 TO SUBPART OOOO OF PART 60—REQUIRED MINIMUM INITIAL SO2 EMISSION REDUCTION EFFICIENCY (Zi) 

H2S content of acid gas (Y), % 

Sulfur feed rate (X), LT/D 

2.0≤X≤5.0 5.0<X≤15.0 15.0<X≤300.0 X>300.0 

Y≥50 ................................................. 79.0 88.51X0.0101Y0.0125 or 99.9, whichever is smaller 

20≤Y<50 ........................................... 79.0 88.51X0.0101Y0.0125 or 97.9, whichever is smaller 97.9 

10≤Y<20 ........................................... 79.0 88.51X0.0101Y0.0125 or 93.5, whichever is smaller 93.5 93.5 

Y<10 ................................................. 79.0 79.0 79.0 79.0 

TABLE 2 TO SUBPART OOOO OF PART 60—REQUIRED MINIMUM SO2 EMISSION REDUCTION EFFICIENCY (Zc) 

H2S content of acid gas (Y), % 

Sulfur feed rate (X), LT/D 

2.0≤X≤5.0 5.0<X≤15.0 15.0<X≤300.0 X>300.0 

Y≥50 ................................................. 74.0 85.35X0.0144Y0.0128 or 99.9, whichever is smaller 

20≤Y<50 ........................................... 74.0 85.35X0.0144Y0.0128 or 97.5, whichever is smaller 97.5 

10≤Y<20 ........................................... 74.0 85.35X0.0144Y0.0128 or 90.8, whichever is smaller 90.8 90.8 

Y<10 ................................................. 74.0 74.0 74.0 74.0 

X = The sulfur feed rate from the sweetening unit (i.e., the H2S in the acid gas), expressed as sulfur, Mg/D(LT/D), rounded to one decimal 

place. 

Y = The sulfur content of the acid gas from the sweetening unit, expressed as mole percent H2S (dry basis) rounded to one decimal place. 

Z = The minimum required sulfur dioxide (SO2) emission reduction efficiency, expressed as percent carried to one decimal place. Zi refers to 

the reduction efficiency required at the initial performance test. Zc refers to the reduction efficiency required on a continuous basis after compliance with Zi has been demonstrated. 

* * * * * 

[FR Doc. 2013–07873 Filed 4–11–13; 8:45 am] 

BILLING CODE 6560–50–P 

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