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REDLINE/STRIKEOUT OF CHANGES - OIL AND NATURAL GAS SECTOR:

RECONSIDERATION OF CERTAIN PROVISIONS OF NEW SOURCE PERFORMANCE 

STANDARDS; FINAL RULE

Subpart OOOO—Standards of Performance for Crude Oil and Natural 

Gas Production, Transmission and Distribution

Sec.

§60.5360 What is the purpose of this subpart?

§60.5365 Am I subject to this subpart?

§60.5370 When must I comply with this subpart?

§60.5375 What standards apply to gas well affected facilities?

§60.5380 What standards apply to centrifugal compressor 

affected facilities?

§60.5385 What standards apply to reciprocating compressor 

affected facilities?

§60.5390 What standards apply to pneumatic controller affected 

facilities?

§60.5395 What standards apply to storage vessel affected 

facilities?

§60.5400 What equipment leak standards apply to affected 

facilities at an onshore natural gas processing plant?

§60.5401 What are the exceptions to the equipment leak 

standards for affected facilities at onshore natural 

gas processing plants?

§60.5402 What are the alternative emission limitations for 

equipment leaks from onshore natural gas processing 

plants?

§60.5405 What standards apply to sweetening units at onshore 

natural gas processing plants?

§60.5406 What test methods and procedures must I use for my 

sweetening units affected facilities at onshore 

natural gas processing plants?

§60.5407 What are the requirements for monitoring of emissions 

and operations from my sweetening unit affected 

facilities at onshore natural gas processing plants?

§60.5408 What is an optional procedure for measuring hydrogen 

sulfide in acid gas—Tutwiler Procedure?

§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 
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vessel affected facility, and my equipment leaks and 

sweetening unit affected facilities at onshore natural 

gas processing plants?

§60.5411 What additional requirements must I meet to determine 

initial compliance for my covers and closed vent 

systems routing materials from storage vessels, 

reciprocating compressors and centrifugal compressor 

wet seal degassing systems?

§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?

§60.5413 What are the performance testing procedures for 

control devices used to demonstrate compliance at my 

storage vessel or centrifugal compressor affected 

facility?

§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?

§60.5416 What are the initial and continuous cover and closed 

vent system inspection and monitoring requirements for 

my storage vessel, centrifugal compressor and 

reciprocating compressor affected facilities?

§60.5417 What are the continuous control device monitoring 

requirements for my storage vessel or centrifugal 

compressor affected facility?

§60.5420 What are my notification, reporting, and recordkeeping 

requirements?

§60.5421 What are my additional recordkeeping requirements for 

my affected facility subject to VOC requirements for 

onshore natural gas processing plants?

§60.5422 What are my additional reporting requirements for my 

affected facility subject to VOC requirements for 

onshore natural gas processing plants?

§60.5423 What additional recordkeeping and reporting 

requirements apply to my sweetening unit affected 

facilities at onshore natural gas processing plants?

§60.5425 What part of the General Provisions apply to me?

§60.5430 What definitions apply to this subpart?

§§60.5431-60.5499 [Reserved]
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Table 1 to Subpart OOOO of Part 60—Required Minimum Initial SO2

Emission Reduction Efficiency (Zi)

Table 2 to Subpart OOOO of Part 60—Required Minimum SO2 Emission 

Reduction Efficiency (Zc)

Table 3 to Subpart OOOO of Part 60—Applicability of General 

Provisions to Subpart OOOO

§60.5360 What is the purpose of this subpart?

This subpart establishes emission standards and compliance 

schedules for the control of volatile organic compounds (VOC) 

and sulfur dioxide (SO2) emissions from affected facilities that 

commence construction, modification or reconstruction after

August 23, 2011. 

§60.5365 Am I subject to this subpart?

You are subject to the applicable provisions of this 

subpart if you are the owner or operator of one or more of the 

onshore affected facilities listed in paragraphs (a) through (g) 

of this section for which you commence construction, 

modification or reconstruction after August 23, 2011. 

(a) Each gas well affected facility, which is a single 

natural gas well. 

(b) Each centrifugal compressor affected facility, which is 

a single centrifugal compressor using wet seals that is located 

between the wellhead and the point of custody transfer to the 

natural gas transmission and storage segment. A centrifugal 

compressor located at a well site, or an adjacent well site and 
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servicing more than one well site, is not an affected facility 

under this subpart. 

(c) Each reciprocating compressor affected facility, which 

is a single reciprocating compressor located between the 

wellhead and the point of custody transfer to the natural gas 

transmission and storage segment. A reciprocating compressor 

located at a well site, or an adjacent well site and servicing 

more than one well site, is not an affected facility under this 

subpart. 

(d)(1) For the oil production segment (between the wellhead 

and the point of custody transfer to an oil pipeline), each 

pneumatic controller affected facility, which is a single 

continuous bleed natural gas-driven pneumatic controller 

operating at a natural gas bleed rate greater than 6 scfh.

(2) For the natural gas production segment (between the 

wellhead and the point of custody transfer to the natural gas 

transmission and storage segment and not including natural gas 

processing plants), each pneumatic controller affected facility, 

which is a single continuous bleed natural gas-driven pneumatic 

controller operating at a natural gas bleed rate greater than 6 

scfh.
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(3) For natural gas processing plants, each pneumatic 

controller affected facility, which is a single continuous bleed 

natural gas-driven pneumatic controller.

(e) Each storage vessel affected facility, which is a 

single storage vessel located in the oil and natural gas 

production segment, natural gas processing segment or natural 

gas transmission and storage segment, and has the potential for 

VOC emissions equal to or greater than 6 tpy as determined 

according to this section by October 15, 2013 for Group 1 

storage vessels and by April 15, 2014, or 30 days after startup 

(whichever is later) for Group 2 storage vessels, except as 

provided in paragraph (e)(1) through (4) of this section. The 

potential for VOC emissions must be calculated using a generally 

accepted model or calculation methodology, based on the maximum 

average daily throughput determined for a 30-day period of 

production prior to the applicable emission determination 

deadline specified in this section. The determination may take 

into account requirements under a legally and practically 

enforceable limit in an operating permit or other requirement 

established under a Federal, State, local or tribal authority.

(1) For each new, modified or reconstructed storage vessel 

receiving liquids pursuant to the standards for gas well 

affected facilities in §60.5375, including wells subject to 
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§60.5375(f), you must determine the potential for VOC emissions 

within 30 days after startup of production.

(2) A storage vessel affected facility that subsequently 

has its potential for VOC emissions decrease to less than 6 tpy 

shall remain an affected facility under this subpart. 

(3) For storage vessels not subject to a legally and 

practically enforceable limit in an operating permit or other 

requirement established under a Federal, State, local or tribal 

authority, any vapor from the storage vessel that is recovered 

and routed to a process through a VRU designed and operated as 

specified in this section is not required to be included in the 

determination of VOC potential to emit for purposes of 

determining affected facility status, provided you comply with 

the requirements in paragraphs (e)(3)(i) through (iv) of this 

section.

(i) You meet the cover requirements specified in 

§60.5411(b).

(ii) You meet the closed vent system requirements specified 

in §60.5411(c).

(iii) You maintain records that document compliance with 

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

(iv) In the event of removal of apparatus that recovers and 

routes vapor to a process, or operation that is inconsistent 
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with the conditions specified in paragraphs (e)(3)(i) and (ii) 

of this section, you must determine the storage vessel’s 

potential for VOC emissions according to this section within 30 

days of such removal or operation.

(4) For each new, reconstructed, or modified storage vessel 

with startup, startup of production, or which is returned to 

service, affected facility status is determined as follows: if 

a storage vessel is reconnected to the original source of 

liquids; used to replace any storage vessel affected facility;

or is installed in parallel with any storage vessel affected 

facility, it is a storage vessel affected facility subject to 

the same requirements as before being removed from service, or 

applicable to the storage vessel affected facility being 

replaced, or with which it is installed in parallel immediately 

upon startup, startup of production, or return to service.

(f) The group of all equipment, except compressors, within 

a process unit is an affected facility.

(1) Addition or replacement of equipment for the purpose of 

process improvement that is accomplished without a capital 

expenditure shall not by itself be considered a modification 

under this subpart. 

(2) Equipment associated with a compressor station, 

dehydration unit, sweetening unit, underground storage vessel, 
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field gas gathering system, or liquefied natural gas unit is 

covered by §§60.5400, 60.5401, 60.5402, 60.5421, and 60.5422 of 

this subpart if it is located at an onshore natural gas 

processing plant. Equipment not located at the onshore natural 

gas processing plant site is exempt from the provisions of 

§§60.5400, 60.5401, 60.5402, 60.5421, and 60.5422 of this 

subpart.

(3) The equipment within a process unit of an affected 

facility located at onshore natural gas processing plants and 

described in paragraph (f) of this section are exempt from this 

subpart if they are subject to and controlled according to 

subparts VVa, GGG or GGGa of this part.

(g) Sweetening units located at onshore natural gas 

processing plants that process natural gas produced from either 

onshore or offshore wells.

(1) Each sweetening unit that processes natural gas is an 

affected facility; and

(2) Each sweetening unit that processes natural gas 

followed by a sulfur recovery unit is an affected facility.

(3) Facilities that have a design capacity less than 2 long 

tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas 

(expressed as sulfur) are required to comply with recordkeeping 

and reporting requirements specified in §60.5423(c) but are not 
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required to comply with §§60.5405 through 60.5407 and 

§§60.5410(g) and 60.5415(g) of this subpart.

(4) Sweetening facilities producing acid gas that is 

completely reinjected into oil-or-gas-bearing geologic strata or 

that is otherwise not released to the atmosphere are not subject 

to §§60.5405 through 60.5407, 60.5410(g), 60.5415(g), and 

60.5423 of this subpart.

(h) The following provisions apply to gas well facilities 

that are hydraulically refractured.

(1) A gas well facility that conducts a well completion 

operation following hydraulic refracturing is not an affected 

facility, provided that the requirements of §60.5375 are met. 

For purposes of this provision, the dates specified in 

§60.5375(a) do not apply, and such facilities, as of October 15, 

2012, must meet the requirements of §60.5375(a)(1) through (4).

(2) A well completion operation following hydraulic 

refracturing at a gas well facility not conducted pursuant to 

§60.5375 is a modification to the gas well affected facility. 

(3) Refracturing of a gas well facility does not affect the 

modification status of other equipment, process units, storage 

vessels, compressors, or pneumatic controllers located at the 

well site. 
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(4) A gas well facility initially constructed after August 

23, 2011, is considered an affected facility regardless of this 

provision.

§60.5370 When must I comply with this subpart?

(a) You must be in compliance with the standards of this 

subpart no later than October 15, 2012 or upon startup, 

whichever is later. 

(b) The provisions for exemption from compliance during 

periods of startup, shutdown and malfunctions provided for in 40 

CFR 60.8(c) do not apply to this subpart.

(c) You are exempt from the obligation to obtain a permit 

under 40 CFR part 70 or 40 CFR part 71, provided you are not 

otherwise required by law to obtain a permit under 40 CFR 

70.3(a) or 40 CFR 71.3(a). Notwithstanding the previous 

sentence, you must continue to comply with the provisions of 

this subpart.

§60.5375 What standards apply to gas well affected facilities?

If you are the owner or operator of a gas well affected 

facility, you must comply with paragraphs (a) through (f) of 

this section. 

(a) Except as provided in paragraph (f) of this section, 

for each well completion operation with hydraulic fracturing 

begun prior to January 1, 2015, you must comply with the 
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requirements of paragraphs (a)(3) and (4) of this section unless 

a more stringent state or local emission control requirement is 

applicable; optionally, you may comply with the requirements of 

paragraphs (a)(1) through (4) of this section. For each new well 

completion operation with hydraulic fracturing begun on or after 

January 1, 2015, you must comply with the requirements in

paragraphs (a)(1) through (4) of this section. You must maintain 

a log as specified in paragraph (b). 

(1) For each stage of the well completion operation, as 

defined in §60.5430, follow the requirements specified in 

paragraph (a)(1)(i) and (ii) of this section.

(i) During the initial flowback stage, route the flowback 

into one or more well completion vessels or storage vessels and 

commence operation of a separator unless it is technically 

infeasible for a separator to function. Any gas present in the 

initial flowback stage is not subject to control under this 

section.

(ii) During the separation flowback stage, route all 

recovered liquids from the separator to one or more well 

completion vessels or storage vessels, re-inject the recovered 

liquids into the well or another well or route the recovered 

liquids to a collection system. Route the recovered gas from the 

separator into a gas flow line or collection system, re-inject 
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the recovered gas into the well or another well, use the 

recovered gas as an on-site fuel source, or use the recovered 

gas for another useful purpose that a purchased fuel or raw 

material would serve. If it is infeasible to route the recovered

gas as required above, follow the requirements in paragraph 

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

flowback stage, it is not technically feasible for a separator 

to function, you must comply with paragraph (a)(1)(i) of this 

section.

(2) All salable quality gas must be routed to the gas flow

line as soon as practicable. In cases where salable quality gas

cannot be directed to the flow line, you must follow the 

requirements in paragraph (a)(3) of this section.

(3) You must capture and direct recovered gas to a 

completion combustion device, except in conditions that may 

result in a fire hazard or explosion, or where high heat 

emissions from a completion combustion device may negatively 

impact tundra, permafrost or waterways. Completion combustion 

devices must be equipped with a reliable continuous ignition 

source

(4) You have a general duty to safely maximize resource 

recovery and minimize releases to the atmosphere during flowback

and subsequent recovery.
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(b) You must maintain a log for each well completion 

operation at each gas well affected facility. The log must be 

completed on a daily basis for the duration of the well 

completion operation and must contain the records specified in 

§60.5420(c)(1)(iii).

(c) You must demonstrate initial compliance with the 

standards that apply to gas well affected facilities as required 

by §60.5410.

(d) You must demonstrate continuous compliance with the 

standards that apply to gas well affected facilities as required 

by §60.5415.

(e) You must perform the required notification, 

recordkeeping and reporting as required by §60.5420.

(f)(1) For each gas well affected facility specified in 

paragraphs (f)(1)(i) and (ii) of this section, you must comply 

with the requirements of paragraphs (f)(2) and (3) of this 

section.

(i) Each well completion operation with hydraulic 

fracturing at a wildcat or delineation well.

(ii) Each well completion operation with hydraulic 

fracturing at a non-wildcat low pressure gas well or nondelineation low pressure gas well.
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(2) Route the flowback into one or more well completion 

vessels and commence operation of a separator unless it is 

technically infeasible for a separator to function. Any gas 

present in the flowback before the separator can function is not 

subject to control under this section. You must capture and 

direct recovered gas to a completion combustion device, except 

in conditions that may result in a fire hazard or explosion, or 

where high heat emissions from a completion combustion device 

may negatively impact tundra, permafrost or waterways. 

Completion combustion devices must be equipped with a reliable 

continuous ignition source. You must also comply with paragraphs 

(a)(4) and (b) through (e) of this section.

(3) You must maintain records specified in 

§60.5420(c)(1)(iii) for wildcat, delineation and low pressure 

gas wells.

§60.5380 What standards apply to centrifugal compressor affected 

facilities?

You must comply with the standards in paragraphs (a) 

through (d) of this section for each centrifugal compressor 

affected facility.

(a)(1) You must reduce VOC emissions from each centrifugal 

compressor wet seal fluid degassing system by 95.0 percent or 

greater.
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(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 process.

(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).

(d) You must perform the required notification, 

recordkeeping, and reporting as required by §60.5420. 

§60.5385 What standards apply to reciprocating compressor 

affected facilities?

You must comply with the standards in paragraphs (a) 

through (d) of this section for each reciprocating compressor 

affected facility.

(a) You must replace the reciprocating compressor rod 

packing according to either paragraph (a)(1) or (2) of this 
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section or you must comply with paragraph (a)(3) of this 

section.

(1) Before the compressor has operated for 26,000 hours. 

The number of hours of operation must be continuously monitored 

beginning upon initial startup of your reciprocating compressor 

affected facility, or October 15, 2012, or the date of the most 

recent reciprocating compressor rod packing replacement, 

whichever is later.

(2) Prior to 36 months from the date of the most recent rod 

packing replacement, or 36 months from the date of startup for a 

new reciprocating compressor for which the rod packing has not 

yet been replaced.

(3) Collect the emissions from the rod packing using a rod 

packing emissions collection system which operates under 

negative pressure and route the rod packing emissions to a 

process through a closed vent system that meets the requirements 

of §60.5411(a).

(b) You must demonstrate initial compliance with standards 

that apply to reciprocating compressor affected facilities as 

required by §60.5410.

(c) You must demonstrate continuous compliance with 

standards that apply to reciprocating compressor affected 

facilities as required by §60.5415.
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(d) You must perform the required notification, 

recordkeeping, and reporting as required by §60.5420. 

§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.

(a) The requirements of paragraph (b)(1) or (c)(1) of this 

section are not required if you determine that the use 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. However, you must tag such pneumatic 

controller with the month and year of installation, 

reconstruction or modification, and identification information

that allows traceability to the records for that pneumatic 

controller, as required in §60.5420(c)(4)(ii).

(b)(1) Each pneumatic controller affected facility at a 

natural gas processing plant must have a bleed rate of zero. 
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(2) Each pneumatic controller affected facility at a 

natural gas processing plant must be tagged with the month and 

year of installation, reconstruction or modification, and 

identification information that allows traceability to the 

records for that pneumatic controller as required in 

§60.5420(c)(4)(iv).

(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

constructed, modified or reconstructed on or after October 15, 

2013, at a location between the wellhead and a natural gas 

processing plant or the point of custody transfer to an oil 

pipeline must be tagged with the month and year of installation, 

reconstruction or modification, and identification information 

that allows traceability to the records for that controller as 

required in §60.5420(c)(4)(iii).

(d) You must demonstrate initial compliance with standards 

that apply to pneumatic controller affected facilities as 

required by §60.5410.
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(e) You must demonstrate continuous compliance with 

standards that apply to pneumatic controller affected facilities 

as required by §60.5415.

(f) You must perform the required notification, 

recordkeeping, and reporting as required by §60.5420, except 

that you are not required to submit the notifications specified 

in §60.5420(a).

§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, 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, you must comply with paragraph (c) of 

this section.

(b) Requirements for Group 1 storage vessel affected 

facilities. If you are the owner or operator of a Group 1 

storage vessel affected facility, you must comply with 

paragraphs (b)(1) and (2) of this section. 
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(1) You must submit a notification identifying each Group 1 

storage vessel affected facility, including its location, with 

your initial annual report as specified in §60.5420(b)(6)(iv). 

(2) You must comply with paragraphs (d) through (g) of this 

section.

(c) Requirements for Group 2 storage vessel affected 

facilities. If you are the owner or operator of a Group 2 

storage vessel affected facility, you must comply with 

paragraphs (d) through (g) of this section. 

(d) You must comply with the control requirements of 

paragraph (d)(1) of this section unless you meet the conditions 

specified in paragraph (d)(2) of this section.

(1) Reduce VOC emissions by 95.0 percent according to the 

schedule specified in (d)(1)(i) and (ii) of this section.

(i) For each Group 2 storage vessel affected facility, you 

must achieve the required emissions reductions by April 15, 

2014, or within 60 days after startup, whichever is later, 

except as otherwise provided below in paragraph (f). For storage 

vessel affected facilities receiving liquids pursuant to the 

standards for gas well affected facilities in §60.5375, you must 

achieve the required emissions reductions within 60 days after 

startup of production as defined in §60.5430.
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(ii) For each Group 1 storage vessel affected facility, you 

must achieve the required emissions reductions by April 15, 

2015.

(2) Maintain the uncontrolled actual VOC emissions from the 

storage vessel affected facility at less than 4 tpy without 

considering control. Prior to using the uncontrolled actual VOC 

emission rate for compliance purposes, you must demonstrate that 

the uncontrolled actual VOC emissions have remained less than 4 

tpy as determined monthly for 12 consecutive months. After such

demonstration, you must determine the uncontrolled actual VOC 

emission rate each month. The uncontrolled actual VOC emissions 

must be calculated using a generally accepted model or 

calculation methodology. Monthly calculations must be based on 

the average throughput for the month. Monthly calculations must 

be separated by at least 14 days. You must comply with paragraph 

(d)(1) of this section if your storage vessel affected facility 

meets the conditions specified in paragraphs (d)(2)(i) or (ii) 

of this section.

(i) If a well feeding the storage vessel affected facility 

undergoes fracturing or refracturing, you must comply with 

paragraph (d)(1) of this section as soon as liquids from the 

well following fracturing or refracturing are routed to the 

storage vessel affected facility.
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(ii) If the monthly emissions determination required in 

this section indicates that VOC emissions from your storage 

vessel affected facility increase to 4 tpy or greater and the 

increase is not associated with fracturing or refracturing of a 

well feeding the storage vessel affected facility, you must 

comply with paragraph (d)(1) of this section within 30 days of 

the monthly calculation.

(e) Control requirements. (1) Except as required in 

paragraph (e)(2) of this section, if you use a control 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 process. 

(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) Requirements for 

Group 1 and Group 2 storage vessel affected facilities that are 

removed from service or returned to service.
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If you remove a Group 1 or Group 2 storage vessel affected 

facility from service, you must comply with paragraphs 

(f)(1)through (3) of this section. A Group 1 or Group 2 storage 

vessel is not an affected facility under this subpart for the 

period that it is removed from service. 

(1) For a storage vessel affected facility to be removed 

from service, you must comply with the requirements of 

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

(i) You must completely empty and degas the storage vessel,

such that the storage vessel no longer contains crude oil, 

condensate, produced water or intermediate hydrocarbon liquids. 

A storage vessel where liquid is left on walls, as bottom 

clingage or in pools due to floor irregularity is considered to 

be completely empty.

(ii) You must submit a notification as required in 

§60.5420(b)(6)(vi) in your next annual report, identifying each

storage vessel affected facility removed from service during 

the reporting period and the date of its removal from service. 

(2) If a storage vessel identified in paragraph (f)(1)(ii)

of this section is returned to service, you must determine its

affected facility status as provided in §60.5365(e)
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(3) For each storage vessel affected facility returned to 

service during the reporting period, you must submit a 

notification in your next annual report as required in 

§60.5420(b)(6)(vii), identifying each storage vessel affected 

facility and the date of its return to service.

(g) Compliance, notification, recordkeeping, and reporting.

You must comply with paragraphs (g)(1) through (3) of this 

section.

(1) You must demonstrate initial compliance with standards 

as required by §60.5410(h) and (i).

(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.

§60.5400 What equipment leak standards apply to affected 

facilities at an onshore natural gas processing plant?

This section applies to the group of all equipment, except 

compressors, within a process unit.
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(a) You must comply with the requirements of §§60.482-

1a(a), (b), and (d), 60.482-2a, and 60.482-4a through 60.482-

11a, except as provided in §60.5401.

(b) You may elect to comply with the requirements of 

§§60.483-1a and 60.483-2a, as an alternative.

(c) You may apply to the Administrator for permission to 

use an alternative means of emission limitation that achieves a 

reduction in emissions of VOC at least equivalent to that 

achieved by the controls required in this subpart according to 

the requirements of §60.5402 of this subpart.

(d) You must comply with the provisions of §60.485a of this 

part except as provided in paragraph (f) of this section.

(e) You must comply with the provisions of §§60.486a and 

60.487a of this part except as provided in §§60.5401, 60.5421, 

and 60.5422 of this part.

(f) You must use the following provision instead of 

§60.485a(d)(1): Each piece of equipment is presumed to be in VOC 

service or in wet gas service unless an owner or operator 

demonstrates that the piece of equipment is not in VOC service 

or in wet gas service. For a piece of equipment to be considered 

not in VOC service, it must be determined that the VOC content 

can be reasonably expected never to exceed 10.0 percent by 

weight. For a piece of equipment to be considered in wet gas 
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service, it must be determined that it contains or contacts the 

field gas before the extraction step in the process. For 

purposes of determining the percent VOC content of the process 

fluid that is contained in or contacts a piece of equipment, 

procedures that conform to the methods described in ASTM E169-

93, E168-92, or E260-96 (incorporated by reference as specified 

in §60.17) must be used.

§60.5401 What are the exceptions to the equipment leak standards 

for affected facilities at onshore natural gas processing 

plants?

(a) You may comply with the following exceptions to the 

provisions of §60.5400(a) and (b).

(b)(1) Each pressure relief device in gas/vapor service may 

be monitored quarterly and within 5 days after each pressure 

release to detect leaks by the methods specified in §60.485a(b) 

except as provided in §60.5400(c) and in paragraph (b)(4) of 

this section, and §60.482-4a(a) through (c) of subpart VVa.

(2) If an instrument reading of 500 ppm or greater is 

measured, a leak is detected.

(3)(i) When a leak is detected, it must be repaired as soon 

as practicable, but no later than 15 calendar days after it is 

detected, except as provided in §60.482-9a.
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(ii) A first attempt at repair must be made no later than 5 

calendar days after each leak is detected.

(4)(i) Any pressure relief device that is located in a 

nonfractionating plant that is monitored only by non-plant 

personnel may be monitored after a pressure release the next 

time the monitoring personnel are on-site, instead of within 5 

days as specified in paragraph (b)(1) of this section and 

§60.482-4a(b)(1) of subpart VVa.

(ii) No pressure relief device described in paragraph 

(b)(4)(i) of this section must be allowed to operate for more 

than 30 days after a pressure release without monitoring.

(c) Sampling connection systems are exempt from the 

requirements of §60.482-5a.

(d) Pumps in light liquid service, valves in gas/vapor and 

light liquid service, pressure relief devices in gas/vapor

service and connectors in gas/vapor service and in light liquid

service that are located at a nonfractionating plant that does 

not have the design capacity to process 283,200 standard cubic 

meters per day (scmd) (10 million standard cubic feet per day) 

or more of field gas are exempt from the routine monitoring 

requirements of §§60.482-2a(a)(1), 60.482-7a(a), 60.482-11a(a),

and paragraph (b)(1) of this section.
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(e) Pumps in light liquid service, valves in gas/vapor and 

light liquid service, pressure relief devices in gas/vapor

service and connectors in gas/vapor service and in light liquid

service within a process unit that is located in the Alaskan 

North Slope are exempt from the routine monitoring requirements 

of §§60.482-2a(a)(1), 60.482-7a(a), 60.482-11a(a), and paragraph 

(b)(1) of this section.

(f) An owner or operator may use the following provisions 

instead of §60.485a(e):

(1) Equipment is in heavy liquid service if the weight 

percent evaporated is 10 percent or less at 150oC (302oF) as 

determined by ASTM Method D86-96 (incorporated by reference as 

specified in §60.17).

(2) Equipment is in light liquid service if the weight 

percent evaporated is greater than 10 percent at 150oC (302oF) as 

determined by ASTM Method D86-96 (incorporated by reference as 

specified in §60.17).

(g) An owner or operator may use the following provisions 

instead of §60.485a(b)(2): A calibration drift assessment shall 

be performed, at a minimum, at the end of each monitoring day. 

Check the instrument using the same calibration gas(es) that 

were used to calibrate the instrument before use. Follow the 

procedures specified in Method 21 of appendix A-7 of this part, 
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Section 10.1, except do not adjust the meter readout to 

correspond to the calibration gas value. Record the instrument 

reading for each scale used as specified in §60.486a(e)(8). 

Divide these readings by the initial calibration values for each 

scale and multiply by 100 to express the calibration drift as a 

percentage. If any calibration drift assessment shows a negative 

drift of more than 10 percent from the initial calibration 

value, then all equipment monitored since the last calibration 

with instrument readings below the appropriate leak definition 

and above the leak definition multiplied by (100 minus the 

percent of negative drift/divided by 100) must be re-monitored. 

If any calibration drift assessment shows a positive drift of 

more than 10 percent from the initial calibration value, then, 

at the owner/operator’s discretion, all equipment since the last 

calibration with instrument readings above the appropriate leak 

definition and below the leak definition multiplied by (100 plus 

the percent of positive drift/divided by 100) may be remonitored.

§60.5402 What are the alternative emission limitations for 

equipment leaks from onshore natural gas processing plants?

(a) If, in the Administrator's judgment, an alternative 

means of emission limitation will achieve a reduction in VOC 

emissions at least equivalent to the reduction in VOC emissions 
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achieved under any design, equipment, work practice or 

operational standard, the Administrator will publish, in the 

Federal Register, a notice permitting the use of that 

alternative means for the purpose of compliance with that 

standard. The notice may condition permission on requirements 

related to the operation and maintenance of the alternative 

means.

(b) Any notice under paragraph (a) of this section must be 

published only after notice and an opportunity for a public 

hearing.

(c) The Administrator will consider applications under this 

section from either owners or operators of affected facilities, 

or manufacturers of control equipment.

(d) The Administrator will treat applications under this 

section according to the following criteria, except in cases 

where the Administrator concludes that other criteria are 

appropriate:

(1) The applicant must collect, verify and submit test 

data, covering a period of at least 12 months, necessary to 

support the finding in paragraph (a) of this section.

(2) If the applicant is an owner or operator of an affected 

facility, the applicant must commit in writing to operate and 

maintain the alternative means so as to achieve a reduction in 
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VOC emissions at least equivalent to the reduction in VOC 

emissions achieved under the design, equipment, work practice or 

operational standard.

§60.5405 What standards apply to sweetening units at onshore 

natural gas processing plants?

(a) During the initial performance test required by 

§60.8(b), you must achieve at a minimum, an SO2 emission 

reduction efficiency (Zi) to be determined from Table 1 of this 

subpart based on the sulfur feed rate (X) and the sulfur content 

of the acid gas (Y) of the affected facility.

(b) After demonstrating compliance with the provisions of 

paragraph (a) of this section, you must achieve at a minimum, an 

SO2 emission reduction efficiency (Zc) to be determined from 

Table 2 of this subpart based on the sulfur feed rate (X) and 

the sulfur content of the acid gas (Y) of the affected facility.

60.5406 What test methods and procedures must I use for my 

sweetening units affected facilities at onshore natural gas 

processing plants?

(a) In conducting the performance tests required in §60.8, 

you must use the test methods in appendix A of this part or 

other methods and procedures as specified in this section, 

except as provided in paragraph §60.8(b).
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(b) During a performance test required by §60.8, you must 

determine the minimum required reduction efficiencies (Z) of SO2

emissions as required in §60.5405(a) and (b) as follows:

(1) The average sulfur feed rate (X) must be computed as 

follows:

 = 

Where:

X = average sulfur feed rate, Mg/D (LT/D).

Qa = average volumetric flow rate of acid gas from sweetening 

unit, dscm/day (dscf/day).

Y = average H2S concentration in acid gas feed from sweetening 

unit, percent by volume, expressed as a decimal.

K = (32 kg S/kg-mole)/((24.04 dscm/kg-mole)(1000 kg S/Mg))

 = 1.331 × 10−3Mg/dscm, for metric units

 = (32 lb S/lb-mole)/((385.36 dscf/lb-mole)(2240 lb S/long 

ton))

 = 3.707 × 10−5 long ton/dscf, for English units.

(2) You must use the continuous readings from the process 

flowmeter to determine the average volumetric flow rate (Qa) in 

dscm/day (dscf/day) of the acid gas from the sweetening unit for 

each run.

(3) You must use the Tutwiler procedure in §60.5408 or a 

chromatographic procedure following ASTM E260-96 (incorporated 

by reference as specified in §60.17) to determine the H2S 

concentration in the acid gas feed from the sweetening unit (Y). 

At least one sample per hour (at equally spaced intervals) must 

be taken during each 4-hour run. The arithmetic mean of all 

samples must be the average H2S concentration (Y) on a dry basis 
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for the run. By multiplying the result from the Tutwiler 

procedure by 1.62 × 10−3, the units gr/100 scf are converted to 

volume percent.

(4) Using the information from paragraphs (b)(1) and (b)(3) 

of this section, Tables 1 and 2 of this subpart must be used to 

determine the required initial (Zi) and continuous (Zc) reduction 

efficiencies of SO2 emissions.

(c) You must determine compliance with the SO2 standards in 

§60.5405(a) or (b) as follows:

(1) You must compute the emission reduction efficiency (R) 

achieved by the sulfur recovery technology for each run using 

the following equation:

 = (100) /( + )

(2) You must use the level indicators or manual soundings 

to measure the liquid sulfur accumulation rate in the product 

storage vessels. You must use readings taken at the beginning 

and end of each run, the tank geometry, sulfur density at the 

storage temperature, and sample duration to determine the sulfur 

production rate (S) in kg/hr (lb/hr) for each run.

(3) You must compute the emission rate of sulfur for each 

run as follows:

 = /

Where:

E = emission rate of sulfur per run, kg/hr.
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Ce = concentration of sulfur equivalent (SO2+ reduced sulfur), 

g/dscm (lb/dscf).

Qsd = volumetric flow rate of effluent gas, dscm/hr (dscf/hr).

K1 = conversion factor, 1000 g/kg (7000 gr/lb).

(4) The concentration (Ce) of sulfur equivalent must be the 

sum of the SO2 and TRS concentrations, after being converted to 

sulfur equivalents. For each run and each of the test methods 

specified in this paragraph (c) of this section, you must use a 

sampling time of at least 4 hours. You must use Method 1 of 

appendix A to part 60 of this chapter to select the sampling 

site. The sampling point in the duct must be at the centroid of 

the cross-section if the area is less than 5 m2 (54 ft2 ) or at a 

point no closer to the walls than 1 m (39 in) if the crosssectional area is 5 m2 or more, and the centroid is more than 1 m 

(39 in.) from the wall.

(i) You must use Method 6 of appendix A to part 60 of this 

chapter to determine the SO2 concentration. You must take eight 

samples of 20 minutes each at 30-minute intervals. The 

arithmetic average must be the concentration for the run. The 

concentration must be multiplied by 0.5 × 10−3 to convert the 

results to sulfur equivalent.

(ii) You must use Method 15 of appendix A to part 60 of 

this chapter to determine the TRS concentration from reductiontype devices or where the oxygen content of the effluent gas is 

less than 1.0 percent by volume. The sampling rate must be at 
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least 3 liters/min (0.1 ft3 /min) to insure minimum residence 

time in the sample line. You must take sixteen samples at 15-

minute intervals. The arithmetic average of all the samples must 

be the concentration for the run. The concentration in ppm 

reduced sulfur as sulfur must be multiplied by 1.333 × 10−3 to 

convert the results to sulfur equivalent.

(iii) You must use Method 16A or Method 15 of appendix A to 

part 60 of this chapter or ANSI/ASME PTC 19.10-1981, Part 10 

(manual portion only) (incorporated by reference as specified in 

§60.17) to determine the reduced sulfur concentration from 

oxidation-type devices or where the oxygen content of the 

effluent gas is greater than 1.0 percent by volume. You must 

take eight samples of 20 minutes each at 30-minute intervals. 

The arithmetic average must be the concentration for the run. 

The concentration in ppm reduced sulfur as sulfur must be 

multiplied by 1.333 × 10−3 to convert the results to sulfur 

equivalent.

(iv) You must use Method 2 of appendix A to part 60 of this 

chapter to determine the volumetric flow rate of the effluent 

gas. A velocity traverse must be conducted at the beginning and 

end of each run. The arithmetic average of the two measurements 

must be used to calculate the volumetric flow rate (Qsd) for the 

run. For the determination of the effluent gas molecular weight, 
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a single integrated sample over the 4-hour period may be taken 

and analyzed or grab samples at 1-hour intervals may be taken, 

analyzed, and averaged. For the moisture content, you must take 

two samples of at least 0.10 dscm (3.5 dscf) and 10 minutes at 

the beginning of the 4-hour run and near the end of the time 

period. The arithmetic average of the two runs must be the 

moisture content for the run.

60.5407 What are the requirements for monitoring of emissions 

and operations from my sweetening unit affected facilities at 

onshore natural gas processing plants?

(a) If your sweetening unit affected facility is located at 

an onshore natural gas processing plant and is subject to the 

provisions of §60.5405(a) or (b) you must install, calibrate, 

maintain, and operate monitoring devices or perform measurements 

to determine the following operations information on a daily 

basis:

(1) The accumulation of sulfur product over each 24-hour 

period. The monitoring method may incorporate the use of an 

instrument to measure and record the liquid sulfur production 

rate, or may be a procedure for measuring and recording the 

sulfur liquid levels in the storage vessels with a level 

indicator or by manual soundings, with subsequent calculation of 

the sulfur production rate based on the tank geometry, stored 
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sulfur density, and elapsed time between readings. The method 

must be designed to be accurate within ±2 percent of the 24-hour 

sulfur accumulation.

(2) The H2S concentration in the acid gas from the 

sweetening unit for each 24-hour period. At least one sample per 

24-hour period must be collected and analyzed using the equation 

specified in §60.5406(b)(1). The Administrator may require you 

to demonstrate that the H2S concentration obtained from one or 

more samples over a 24-hour period is within ±20 percent of the 

average of 12 samples collected at equally spaced intervals 

during the 24-hour period. In instances where the H2S 

concentration of a single sample is not within ±20 percent of 

the average of the 12 equally spaced samples, the Administrator 

may require a more frequent sampling schedule.

(3) The average acid gas flow rate from the sweetening 

unit. You must install and operate a monitoring device to 

continuously measure the flow rate of acid gas. The monitoring 

device reading must be recorded at least once per hour during 

each 24-hour period. The average acid gas flow rate must be 

computed from the individual readings.

(4) The sulfur feed rate (X). For each 24-hour period, you 

must compute X using the equation specified in §60.5406(b)(1).
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(5) The required sulfur dioxide emission reduction 

efficiency for the 24-hour period. You must use the sulfur feed 

rate and the H2S concentration in the acid gas for the 24-hour 

period, as applicable, to determine the required reduction 

efficiency in accordance with the provisions of §60.5405(b).

(b) Where compliance is achieved through the use of an 

oxidation control system or a reduction control system followed 

by a continually operated incineration device, you must install, 

calibrate, maintain, and operate monitoring devices and 

continuous emission monitors as follows:

(1) A continuous monitoring system to measure the total 

sulfur emission rate (E) of SO2 in the gases discharged to the 

atmosphere. The SO2 emission rate must be expressed in terms of

equivalent sulfur mass flow rates (kg/hr (lb/hr)). The span of 

this monitoring system must be set so that the equivalent 

emission limit of §60.5405(b) will be between 30 percent and 70 

percent of the measurement range of the instrument system.

(2) Except as provided in paragraph (b)(3) of this section: 

A monitoring device to measure the temperature of the gas 

leaving the combustion zone of the incinerator, if compliance 

with §60.5405(a) is achieved through the use of an oxidation 

control system or a reduction control system followed by a 

continually operated incineration device. The monitoring device 
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must be certified by the manufacturer to be accurate to within 

±1 percent of the temperature being measured.

(3) When performance tests are conducted under the 

provision of §60.8 to demonstrate compliance with the standards 

under §60.5405, the temperature of the gas leaving the 

incinerator combustion zone must be determined using the 

monitoring device. If the volumetric ratio of sulfur dioxide to 

sulfur dioxide plus total reduced sulfur (expressed as SO2) in 

the gas leaving the incinerator is equal to or less than 0.98, 

then temperature monitoring may be used to demonstrate that 

sulfur dioxide emission monitoring is sufficient to determine 

total sulfur emissions. At all times during the operation of the 

facility, you must maintain the average temperature of the gas 

leaving the combustion zone of the incinerator at or above the 

appropriate level determined during the most recent performance 

test to ensure the sulfur compound oxidation criteria are met. 

Operation at lower average temperatures may be considered by the 

Administrator to be unacceptable operation and maintenance of 

the affected facility. You may request that the minimum 

incinerator temperature be reestablished by conducting new 

performance tests under §60.8.

(4) Upon promulgation of a performance specification of 

continuous monitoring systems for total reduced sulfur compounds 
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at sulfur recovery plants, you may, as an alternative to 

paragraph (b)(2) of this section, install, calibrate, maintain, 

and operate a continuous emission monitoring system for total 

reduced sulfur compounds as required in paragraph (d) of this 

section in addition to a sulfur dioxide emission monitoring 

system. The sum of the equivalent sulfur mass emission rates 

from the two monitoring systems must be used to compute the 

total sulfur emission rate (E).

(c) Where compliance is achieved through the use of a 

reduction control system not followed by a continually operated 

incineration device, you must install, calibrate, maintain, and 

operate a continuous monitoring system to measure the emission 

rate of reduced sulfur compounds as SO2 equivalent in the gases 

discharged to the atmosphere. The SO2 equivalent compound 

emission rate must be expressed in terms of equivalent sulfur 

mass flow rates (kg/hr (lb/hr)). The span of this monitoring 

system must be set so that the equivalent emission limit of 

§60.5405(b) will be between 30 and 70 percent of the measurement 

range of the system. This requirement becomes effective upon 

promulgation of a performance specification for continuous 

monitoring systems for total reduced sulfur compounds at sulfur 

recovery plants.
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(d) For those sources required to comply with paragraph (b) 

or (c) of this section, you must calculate the average sulfur 

emission reduction efficiency achieved (R) for each 24-hour 

clock internal. The 24-hour interval may begin and end at any 

selected clock time, but must be consistent. You must compute 

the 24-hour average reduction efficiency (R) based on the 24-

hour average sulfur production rate (S) and sulfur emission rate 

(E), using the equation in §60.5406(c)(1).

(1) You must use data obtained from the sulfur production 

rate monitoring device specified in paragraph (a) of this 

section to determine S.

(2) You must use data obtained from the sulfur emission 

rate monitoring systems specified in paragraphs (b) or (c) of 

this section to calculate a 24-hour average for the sulfur 

emission rate (E). The monitoring system must provide at least 

one data point in each successive 15-minute interval. You must 

use at least two data points to calculate each 1-hour average. 

You must use a minimum of 18 1-hour averages to compute each 24-

hour average.

(e) In lieu of complying with paragraphs (b) or (c) of this 

section, those sources with a design capacity of less than 152 

Mg/D (150 LT/D) of H2S expressed as sulfur may calculate the 
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sulfur emission reduction efficiency achieved for each 24-hour 

period by:

 =





Where:

R = The sulfur dioxide removal efficiency achieved during the 

24-hour period, percent.

K2 = Conversion factor, 0.02400 Mg/D per kg/hr (0.01071 LT/D per 

lb/hr).

S = The sulfur production rate during the 24-hour period, kg/hr 

(lb/hr).

X = The sulfur feed rate in the acid gas, Mg/D (LT/D).

(f) The monitoring devices required in paragraphs (b)(1), 

(b)(3) and (c) of this section must be calibrated at least 

annually according to the manufacturer's specifications, as 

required by §60.13(b).

(g) The continuous emission monitoring systems required in 

paragraphs (b)(1), (b)(3), and (c) of this section must be 

subject to the emission monitoring requirements of §60.13 of the 

General Provisions. For conducting the continuous emission 

monitoring system performance evaluation required by §60.13(c), 

Performance Specification 2 of appendix B to part 60 of this 

chapter must apply, and Method 6 must be used for systems 

required by paragraph (b) of this section.

§60.5408 What is an optional procedure for measuring hydrogen 

sulfide in acid gas—Tutwiler Procedure?
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The Tutwiler procedure may be found in the Gas Engineers 

Handbook, Fuel Gas Engineering practices, The Industrial Press, 

93 Worth Street, New York, NY, 1966, First Edition, Second 

Printing, page 6/25 (Docket A-80-20-A, Entry II-I-67).

(a) When an instantaneous sample is desired and H2S 

concentration is ten grains per 1000 cubic foot or more, a 100 

ml Tutwiler burette is used. For concentrations less than ten 

grains, a 500 ml Tutwiler burette and more dilute solutions are 

used. In principle, this method consists of titrating hydrogen 

sulfide in a gas sample directly with a standard solution of 

iodine.

(b) Apparatus. (See Figure 1 of this subpart) A 100 or 500 

ml capacity Tutwiler burette, with two-way glass stopcock at 

bottom and three-way stopcock at top which connect either with 

inlet tubulature or glass-stoppered cylinder, 10 ml capacity, 

graduated in 0.1 ml subdivision; rubber tubing connecting 

burette with leveling bottle.

(c) Reagents. (1) Iodine stock solution, 0.1N. Weight 12.7 

g iodine, and 20 to 25 g cp potassium iodide for each liter of 

solution. Dissolve KI in as little water as necessary; dissolve 

iodine in concentrated KI solution, make up to proper volume, 

and store in glass-stoppered brown glass bottle.
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(2) Standard iodine solution, 1 ml=0.001771 g I. Transfer 

33.7 ml of above 0.1N stock solution into a 250 ml volumetric 

flask; add water to mark and mix well. Then, for 100 ml sample 

of gas, 1 ml of standard iodine solution is equivalent to 100 

grains H2S per cubic feet of gas.

(3) Starch solution. Rub into a thin paste about one 

teaspoonful of wheat starch with a little water; pour into about 

a pint of boiling water; stir; let cool and decant off clear 

solution. Make fresh solution every few days.

(d) Procedure. Fill leveling bulb with starch solution. 

Raise (L), open cock (G), open (F) to (A), and close (F) when 

solutions starts to run out of gas inlet. Close (G). Purge gas 

sampling line and connect with (A). Lower (L) and open (F) and 

(G). When liquid level is several ml past the 100 ml mark, close 

(G) and (F), and disconnect sampling tube. Open (G) and bring 

starch solution to 100 ml mark by raising (L); then close (G). 

Open (F) momentarily, to bring gas in burette to atmospheric 

pressure, and close (F). Open (G), bring liquid level down to 10 

ml mark by lowering (L). Close (G), clamp rubber tubing near (E) 

and disconnect it from burette. Rinse graduated cylinder with a 

standard iodine solution (0.00171 g I per ml); fill cylinder and 

record reading. Introduce successive small amounts of iodine 

thru (F); shake well after each addition; continue until a faint 
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permanent blue color is obtained. Record reading; subtract from 

previous reading, and call difference D.

(e) With every fresh stock of starch solution perform a

blank test as follows: Introduce fresh starch solution into 

burette up to 100 ml mark. Close (F) and (G). Lower (L) and open 

(G). When liquid level reaches the 10 ml mark, close (G). With 

air in burette, titrate as during a test and up to same end 

point. Call ml of iodine used C. Then,

Grains H2S per 100 cubic foot of gas = 100(D—C)

(f) Greater sensitivity can be attained if a 500 ml 

capacity Tutwiler burette is used with a more dilute (0.001N) 

iodine solution. Concentrations less than 1.0 grains per 100 

cubic foot can be determined in this way. Usually, the starchiodine end point is much less distinct, and a blank 

determination of end point, with H2S-free gas or air, is 

required.
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Figure 1. Tutwiler burette (lettered items mentioned in text).
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§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 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) To achieve initial compliance with the standards for 

each well completion operation conducted at your gas well

affected facility you must comply with paragraphs (a)(1) through 

(a)(4) of this section.

(1) You must submit the notification required in 

§60.5420(a)(2).

(2) You must submit the initial annual report for your well 

affected facility as required in §60.5420(b).
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(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)(1) To achieve initial compliance with standards for 

your centrifugal compressor affected facility you must reduce 
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VOC emissions from each centrifugal compressor wet seal fluid 

degassing system by 95.0 percent or greater as required by 

§60.5380 and as demonstrated by the requirements of §60.5413.

(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 process.

(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.

(6) You must submit the notifications required in 

60.7(a)(1), (3), and (4). 
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(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).

(c) To achieve initial compliance with the standards for 

each reciprocating compressor affected facility you must comply

with paragraphs (c)(1) through (4) of this section.

(1) If complying with §60.5385(a)(1) or (2), during the 

initial compliance period, you must continuously monitor the 

number of hours of operation or track the number of months since 

the last rod packing replacement.

(2) If complying with §60.5385(a)(3), you must operate the 

rod packing emissions collection system under negative pressure 

and route emissions to a process through a closed vent system 

that meets the requirements of §60.5411(a).

(3) You must submit the initial annual report for your 

reciprocating compressor as required in §60.5420(b).

(4) You must maintain the records as specified in 

§60.5420(c)(3) for each reciprocating compressor affected 

facility.
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(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) You own or operate a pneumatic controller affected 

facility located between the wellhead and a natural gas 

processing plant and the manufacturer’s design specifications 

indicate that the controller emits less than or equal to 6 

standard cubic feet of gas per hour.

(4) You must tag each new pneumatic controller affected 

facility according to the requirements of §60.5390(b)(2) or 

(c)(2).

(5) You must include the information in paragraph (d)(1) of 

this section and a listing of the pneumatic controller affected 
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facilities specified in paragraphs (d)(2) and (3) of this 

section in the initial annual report submitted for your 

pneumatic controller affected facilities constructed, modified 

or reconstructed during the period covered by the annual report 

according to the requirements of §60.5420(b).

(6) You must maintain the records as specified in 

§60.5420(c)(4) for each pneumatic controller affected facility.

(e) [Reserved]

(f) For affected facilities at onshore natural gas 

processing plants, initial compliance with the VOC requirements 

is demonstrated if you are in compliance with the requirements 

of §60.5400.

(g) For sweetening unit affected facilities at onshore 

natural gas processing plants, initial compliance is 

demonstrated according to paragraphs (g)(1) through (3) of this 

section.

(1) To determine compliance with the standards for SO2

specified in §60.5405(a), during the initial performance test as 

required by §60.8, the minimum required sulfur dioxide emission 

reduction efficiency (Zi) is compared to the emission reduction 

efficiency (R) achieved by the sulfur recovery technology as 

specified in paragraphs (g)(1)(i) and (ii) of this section.

(i) If R ≥ Zi, your affected facility is in compliance.
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(ii) If R < Zi, your affected facility is not in compliance.

(2) The emission reduction efficiency (R) achieved by the 

sulfur reduction technology must be determined using the 

procedures in §60.5406(c)(1).

(3) You have submitted the results of paragraphs (g)(1) and 

(2) of this section in the initial annual report submitted for 

your sweetening unit affected facilities at onshore natural gas 

processing plants. 

(h) For each storage vessel affected facility, you must 

comply with paragraphs (h)(1) through (5) of this section. For a 

Group 1 storage vessel affected facility, you must demonstrate 

initial compliance by April 15, 2015, except as otherwise 

provided in paragraph (i) of this section. For a Group 2 storage 

vessel affected facility, you must demonstrate initial 

compliance by April 15, 2014, or within 60 days after startup, 

whichever is later.

(1) You must determine the potential VOC emission rate as 

specified in §60.5365(e).

(2) You must reduce VOC emissions in accordance with 

§60.5395(d).

(3) If you use a control device to reduce emissions, or if 

you route emissions to a process, you must demonstrate initial 

compliance by meeting the requirements in §60.5395(e).
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(4) You must submit the information required for your

storage vessel affected facility as specified in §60.5420(b). 

(5) You must maintain the records required for your storage 

vessel affected facility, as specified in §60.5420(c)(5) through

(8) and §60.5420(c)(12) and (13) for each storage vessel 

affected facility.

(i) For each Group 1 storage vessel affected facility, you 

must submit the notification specified in §60.5395(b)(2) with 

the initial annual report specified in §60.5420(b)(6).

§60.5411 What additional requirements must I meet to determine 

initial compliance for my covers and closed vent systems routing 

materials from storage vessels, reciprocating compressors and 

centrifugal compressor wet seal degassing systems?

You must meet the applicable requirements of this section 

for each cover and closed vent system used to comply with the 

emission standards for your storage vessel, reciprocating 

compressor or centrifugal compressor affected facility.

(a) Closed vent system requirements for reciprocating 

compressors and for centrifugal compressor wet seal degassing 

systems.

(1) You must design the closed vent system to route all 

gases, vapors, and fumes emitted from the material in the 

reciprocating compressor rod packing emissions collection system 
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or the wet seal fluid degassing system to a control device or to 

a process that meets the requirements specified in §60.5412(a) 

through (c).

(2) You must design and operate the closed vent system with 

no detectable emissions as demonstrated by §60.5416(b).

(3) You must meet the requirements specified in paragraphs 

(a)(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.

(i) Except as provided in paragraph (a)(3)(ii) of this 

section, you must comply with either paragraph (a)(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 process 

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 or process to the 

atmosphere.
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(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 (a)(3)(i) of this section.

(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) Each cover opening shall be secured in a closed, sealed 

position (e.g., covered by a gasketed lid or cap) whenever 

material is in the unit on which the cover is installed except 

during those times when it is necessary to use an opening as 

follows:

(i) To add material to, or remove material from the unit 

(this includes openings necessary to equalize or balance the 

internal pressure of the unit following changes in the level of 

the material in the unit);

(ii) To inspect or sample the material in the unit;
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(iii) To inspect, maintain, repair, or replace equipment 

located inside the unit; or

(iv) To vent liquids, gases, or fumes from the unit through 

a closed-vent system designed and operated in accordance with 

the requirements of paragraph (a) or (c) of this section to a 

control device or to a process.

(3) Each storage vessel thief hatch shall be equipped, 

maintained and operated with a weighted mechanism or equivalent,

to ensure that the lid remains properly seated. You must select 

gasket material for the hatch based on composition of the fluid 

in the storage vessel and weather conditions.

(c) Closed vent system requirements for storage vessel

affected facilities using a control device or routing emissions 

to a process.

(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 process.

(2) You must design and operate a closed vent system with 

no detectable emissions, as determined using olfactory, visual 

and auditory inspections. Each closed vent system that routes 

emissions to a process must be operational 95 percent of the 

year or greater.
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(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 process.

(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 process 

to the atmosphere that sounds an alarm, or, initiates 

notification via remote alarm to the nearest field office, when 

the bypass device is open such that the stream is being, or 

could be, diverted away from the control device or process 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.
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§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?

You must meet the applicable requirements of this section 

for each control device used to comply with the emission 

standards for your 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, 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 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.

(i) You must 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.
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(ii) You must reduce the concentration of TOC in the 

exhaust gases at the outlet to the device to a level equal to or 

less than 20 parts per million by volume on a dry basis 

corrected to 3 percent oxygen as determined in accordance with 

the requirements of §60.5413.

(iii) You must operate at a minimum temperature of 760°C 

for a control device that can demonstrate a uniform combustion 

zone temperature during the performance test conducted under 

§60.5413.

(iv) If a boiler or process heater is used as the control 

device, then you must introduce the vent stream into the flame 

zone of the boiler or process heater.

(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).

(3) You must design and operate a flare in accordance with 

the requirements of §60.5413.
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(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 
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longer than the carbon service life established according to 

§60.5413(c)(2) or (3) or according to the design required 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 (12). 

(2) You must either regenerate, reactivate, or burn the 

spent carbon removed from the carbon adsorption system in one of 

the units specified in paragraphs (c)(2)(i) through (vii) of 

this section.

(i) Regenerate or reactivate the spent carbon in a thermal 

treatment unit for which you have been issued a final permit 

under 40 CFR part 270 that implements the requirements of 40 CFR 

part 264, subpart X.

(ii) Regenerate or reactivate the spent carbon in a thermal 

treatment unit equipped with and operating air emission controls 

in accordance with this section.

(iii) Regenerate or reactivate the spent carbon in a 

thermal treatment unit equipped with and operating organic air 

emission controls in accordance with an emissions standard for 

VOC under another subpart in 40 CFR part 60 or this part.

(iv) Burn the spent carbon in a hazardous waste incinerator 

for which the owner or operator has been issued a final permit 
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under 40 CFR part 270 that implements the requirements of 40 CFR 

part 264, subpart O.

(v) Burn the spent carbon in a hazardous waste incinerator 

which you have designed and operated in accordance with the 

requirements of 40 CFR part 265, subpart O.

(vi) Burn the spent carbon in a boiler or industrial 

furnace for which you have been issued a final permit under 40 

CFR part 270 that implements the requirements of 40 CFR part 

266, subpart H.

(vii) Burn the spent carbon in a boiler or industrial 

furnace that you have designed and operated in accordance with 

the interim status requirements of 40 CFR part 266, subpart H.

(d) Each control device used to meet the emission reduction 

standard in §60.5395(d) for your storage vessel affected 

facility must be installed according to paragraphs (d)(1) 

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

paragraph (d)(1) of this section, you may install a control 

device model tested under §60.5413(d), which meets the criteria 

in §60.5413(d)(11) and §60.5413(e).

(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 
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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 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 
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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.

§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 
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manufacturer applicable to both storage vessel and centrifugal 

compressor affected facilities. 

(a) Performance test exemptions. You are exempt from the 

requirements to conduct performance tests and design analyses if 

you use any of the control devices described in paragraphs 

(a)(1) through (7) of this section.

(1) A flare that is designed and operated in accordance 

with §60.18(b). You must conduct the compliance determination 

using Method 22 at 40 CFR part 60, appendix A-7, to determine 

visible emissions.

(2) A boiler or process heater with a design heat input 

capacity of 44 megawatts or greater.

(3) A boiler or process heater into which the vent stream 

is introduced with the primary fuel or is used as the primary 

fuel.

(4) A boiler or process heater burning hazardous waste for 

which you have either been issued a final permit under 40 CFR 

part 270 and comply with the requirements of 40 CFR part 266, 

subpart H; or you have certified compliance with the interim 

status requirements of 40 CFR part 266, subpart H.

(5) A hazardous waste incinerator for which you have been 

issued a final permit under 40 CFR part 270 and comply with the 

requirements of 40 CFR part 264, subpart O; or you have 
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certified compliance with the interim status requirements of 40 

CFR part 265, subpart O.

(6) A performance test is waived in accordance with 

§60.8(b).

(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.

(b) Test methods and procedures. You must use the test 

methods and procedures specified in paragraphs (b)(1) through(5) 

of this section, as applicable, for each performance test 

conducted to demonstrate that a control device meets the 

requirements of §60.5412(a). You must conduct the initial and 

periodic performance tests according to the schedule specified 

in paragraph (b)(5) of this section.

(1) You must use Method 1 or 1A at 40 CFR part 60, appendix 

A-1, as appropriate, to select the sampling sites specified in 

paragraphs (b)(1)(i) and (ii) of this section. Any references to 

particulate mentioned in Methods 1 and 1A do not apply to this

section.

(i) Sampling sites must be located at the inlet of the 

first control device, and at the outlet of the final control 
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device, to determine compliance with the control device percent 

reduction requirement specified in §60.5412(a)(1)(i) or (a)(2).

(ii) The sampling site must be located at the outlet of the 

combustion device to determine compliance with the enclosed 

combustion device total TOC concentration limit specified in 

§60.5412(a)(1)(ii).

(2) You must determine the gas volumetric flowrate using 

Method 2, 2A, 2C, or 2D at 40 CFR part 60, appendix A-2, as 

appropriate.

(3) To determine compliance with the control device percent 

reduction performance requirement in §60.5412(a)(1)(i) or 

(a)(2), you must use Method 25A at 40 CFR part 60, appendix A-7. 

You must use the procedures in paragraphs (b)(3)(i) through (iv) 

of this section to calculate percent reduction efficiency.

(i) For each run, you must take either an integrated sample 

or a minimum of four grab samples per hour. If grab sampling is 

used, then the samples must be taken at approximately equal 

intervals in time, such as 15-minute intervals during the run.

(ii) You must compute the mass rate of TOC (minus methane 

and ethane) using the equations and procedures specified in 

paragraphs (b)(3)(ii)(A) and (B) of this section. 

(A) You must use the following equations:
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 =  







 =  







Where:

Ei, Eo = Mass rate of TOC (minus methane and ethane) at the 

inlet and outlet of the control device, respectively, dry basis, 

kilogram per hour.

K2 = Constant, 2.494 × 10−6 (parts per million) (gram-mole 

per standard cubic meter) (kilogram/gram) (minute/hour), where 

standard temperature (gram-mole per standard cubic meter) is 

20°C.

Cij, Coj = Concentration of sample component j of the gas 

stream at the inlet and outlet of the control device, 

respectively, dry basis, parts per million by volume.

Mij, Moj = Molecular weight of sample component j of the gas 

stream at the inlet and outlet of the control device, 

respectively, gram/gram-mole.

Qi, Qo = Flowrate of gas stream at the inlet and outlet of 

the control device, respectively, dry standard cubic meter per 

minute.
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n = Number of components in sample.

(B) When calculating the TOC mass rate, you must sum all 

organic compounds (minus methane and ethane) measured by Method 

25A at 40 CFR part 60, appendix A-7 using the equations in 

paragraph (b)(3)(ii)(A) of this section.

(iii) You must calculate the percent reduction in TOC 

(minus methane and ethane) as follows:

 =

 − 



∗ 100%

Where:

Rcd = Control efficiency of control device, percent.

Ei = Mass rate of TOC (minus methane and ethane) at the 

inlet to the control device as calculated under paragraph 

(b)(3)(ii) of this section, kilograms TOC per hour or kilograms 

HAP per hour.

Eo = Mass rate of TOC (minus methane and ethane) at the 

outlet of the control device, as calculated under paragraph 

(b)(3)(ii) of this section, kilograms TOC per hour per hour.

(iv) If the vent stream entering a boiler or process heater 

with a design capacity less than 44 megawatts is introduced with 

the combustion air or as a secondary fuel, you must determine 

the weight-percent reduction of total TOC (minus methane and 

ethane) across the device by comparing the TOC (minus methane 

and ethane) in all combusted vent streams and primary and 
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secondary fuels with the TOC (minus methane and ethane) exiting 

the device, respectively.

(4) You must use Method 25A at 40 CFR part 60, appendix A-7 

to measure TOC (minus methane and ethane) to determine 

compliance with the enclosed combustion device total VOC 

concentration limit specified in §60.5412(a)(1)(ii). You must 

calculate parts per million by volume concentration and correct 

to 3 percent oxygen, using the procedures in paragraphs 

(b)(4)(i) through (iii) of this section. 

(i) For each run, you must take either an integrated sample 

or a minimum of four grab samples per hour. If grab sampling is 

used, then the samples must be taken at approximately equal 

intervals in time, such as 15-minute intervals during the run.

(ii) You must calculate the TOC concentration for each run as 

follows:

 = 

∑ 













Where:

CTOC = Concentration of total organic compounds minus methane 

and ethane, dry basis, parts per million by volume.

Cji = Concentration of sample component j of sample i, dry 

basis, parts per million by volume.
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n = Number of components in the sample.

x = Number of samples in the sample run.

(iii) You must correct the TOC concentration to 3 percent 

oxygen as specified in paragraphs (b)(4)(iii)(A) and (B) of this 

section.

(A) You must use the emission rate correction factor for 

excess air, integrated sampling and analysis procedures of 

Method 3A or 3B at 40 CFR part 60, appendix A, ASTM D6522-00 

(Reapproved 2005), or ANSI/ASME PTC 19.10-1981, Part 10 (manual 

portion only) (incorporated by reference as specified in §60.17)

to determine the oxygen concentration. The samples must be taken 

during the same time that the samples are taken for determining 

TOC concentration.

(B) You must correct the TOC concentration for percent 

oxygen as follows:

 =  

17.9

20.9 − %



Where:

Cc = TOC concentration corrected to 3 percent oxygen, dry 

basis, parts per million by volume.

Cm = TOC concentration, dry basis, parts per million by 

volume.
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%O2d = Concentration of oxygen, dry basis, percent by volume.

(5) You must conduct performance tests according to the 

schedule specified in paragraphs (b)(5)(i) and (ii) of this 

section.

(i) You must conduct an initial performance test within 180 

days after initial startup for your affected facility. You must 

submit the performance test results as required in 

§60.5420(b)(7).

(ii) You must conduct periodic performance tests for all 

control devices required to conduct initial performance tests 

except as specified in paragraphs (b)(5)(ii)(A) and (B) of this 

section. You must conduct the first periodic performance test no 

later than 60 months after the initial performance test required 

in paragraph (b)(5)(i) of this section. You must conduct 

subsequent periodic performance tests at intervals no longer 

than 60 months following the previous periodic performance test 

or whenever you desire to establish a new operating limit. You 

must submit the periodic performance test results as specified 

in §60.5420(b)(7). Combustion control devices meeting the 

criteria in either paragraph (b)(5)(ii)(A) or (B) of this 

section are not required to conduct periodic performance tests.

(A) A control device whose model is tested under, and meets 

the criteria of paragraph (d) of this section.
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(B) A combustion control device tested under paragraph (b) 

of this section that meets the outlet TOC performance level 

specified in §60.5412(a)(1)(ii) and that establishes a 

correlation between firebox or combustion chamber temperature 

and the TOC performance level.

(c) Control device design analysis to meet the requirements 

of §60.5412(a). (1) For a condenser, the design analysis must 

include an analysis of the vent stream composition, constituent 

concentrations, flowrate, relative humidity, and temperature, 

and must establish the design outlet organic compound 

concentration level, design average temperature of the condenser 

exhaust vent stream, and the design average temperatures of the 

coolant fluid at the condenser inlet and outlet.

(2) For a regenerable carbon adsorption system, the design 

analysis shall include the vent stream composition, constituent 

concentrations, flowrate, relative humidity, and temperature, 

and shall establish the design exhaust vent stream organic 

compound concentration level, adsorption cycle time, number and 

capacity of carbon beds, type and working capacity of activated 

carbon used for the carbon beds, design total regeneration 

stream flow over the period of each complete carbon bed 

regeneration cycle, design carbon bed temperature after 
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regeneration, design carbon bed regeneration time, and design 

service life of the carbon.

(3) For a nonregenerable carbon adsorption system, such as 

a carbon canister, the design analysis shall include the vent 

stream composition, constituent concentrations, flowrate, 

relative humidity, and temperature, and shall establish the 

design exhaust vent stream organic compound concentration level, 

capacity of the carbon bed, type and working capacity of 

activated carbon used for the carbon bed, and design carbon 

replacement interval based on the total carbon working capacity 

of the control device and source operating schedule. In 

addition, these systems will incorporate dual carbon canisters 

in case of emission breakthrough occurring in one canister.

(4) If you and the Administrator do not agree on a 

demonstration of control device performance using a design 

analysis, then you must perform a performance test in accordance 

with the requirements of paragraph (b) of this section to 

resolve the disagreement. The Administrator may choose to have 

an authorized representative observe the performance test.

(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 
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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. 
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(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 
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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.

(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. 
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(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 
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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 
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the procedure specified in (d)(7)(i)(A) through (B) of this 

section. Analyze the bag sample using a gas chromatographthermal 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 
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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 volumedry (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. 
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(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:

Ccorr = Cmeas 

3

CO



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.
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(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 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.
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(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 paragraph must submit the information 

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

required by this section in accordance with §60.5420 (b)(8).

(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. 
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(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.
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(e) Continuous compliance for combustion control devices 

tested by the manufacturer in accordance with paragraph (d) of 

this section. This paragraph applies to the demonstration of 

compliance for a combustion control device tested under the 

provisions in paragraph (d) of this section. Owners or operators 

must demonstrate that a control device achieves the performance 

requirements in (d)(11) of this section by installing a device 

tested under paragraph (d) of this section and complying with 

the criteria specified in paragraphs (e)(1) through (7) of this 

section.

(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 
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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 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 website: epa.gov/airquality/oilandgas/.

(7) Ensure that each enclosed combustion device is 

maintained in a leak free condition. 

§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?
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(a) For each gas well affected facility, you must 

demonstrate continuous compliance by submitting the reports 

required by §60.5420(b) and maintaining the records for each 

completion operation specified in §60.5420(c)(1).

(b) For each centrifugal compressor affected facility, you 

must demonstrate continuous compliance according to paragraphs 

(b)(1) through (3) of this section.

(1) You must reduce VOC emissions from the wet seal fluid 

degassing system by 95.0 percent or greater.

(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.
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(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 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 
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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).
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(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 section 11 of 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 section 11 of 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 for inspection.

(D) Following return to operation from maintenance or 

repair activity, each device must pass a Method 22, 40 CFR part 
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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 
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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.

(3) You must submit the annual report required by 

60.5420(b) and maintain the records as specified in 

§60.5420(c)(2).
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(c) For each reciprocating compressor affected facility

complying with §60.5385(a)(1) or (2), you must demonstrate

continuous compliance according to paragraphs (c)(1) through (3) 

of this section. For each reciprocating compressor affected 

facility complying with §60.5385(a)(3), you must demonstrate

continuous compliance according to paragraph (c)(4).

(1) You must continuously monitor the number of hours of 

operation for each reciprocating compressor affected facility or 

track the number of months since initial startup, or October 15, 

2012, or the date of the most recent reciprocating compressor 

rod packing replacement, whichever is later. 

(2) You must submit the annual report as required in 

§60.5420(b) and maintain records as required in §60.5420(c)(3).

(3) You must replace the reciprocating compressor rod 

packing before the total number of hours of operation reaches 

26,000 hours or the number of months since the most recent rod 

packing replacement reaches 36 months.

(4) You must operate the rod packing emissions collection 

system under negative pressure and continuously comply with the 

closed vent requirements in §60.5411(a).
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(d) For each pneumatic controller affected facility, you 

must demonstrate continuous compliance according to paragraphs 

(d)(1) through (3) of this section.

(1) You must continuously operate the pneumatic controllers 

as required in §60.5390(a), (b), or (c).

(2) You must submit the annual report as required in 

§60.5420(b).

(3) You must maintain records as required in 

§60.5420(c)(4).

(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 process to meet the requirement of 

§60.5395(d)(1).

(1) [Reserved]

(2) [Reserved]

(3) For each storage vessel affected facility, you must 

comply with paragraphs (e)(3)(i) and (ii) of this section.

(i) You must reduce VOC emissions as specified in 

§60.5395(d).

(ii) For each control device installed to meet the 

requirements of §60.5395(d), you must demonstrate continuous 

compliance with the performance requirements of §60.5412(d) for 
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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

process must be operated as specified in §60.5411(c)(2).

(f) For affected facilities at onshore natural gas 

processing plants, continuous compliance with VOC requirements 

is demonstrated if you are in compliance with the requirements 

of §60.5400.

(g) For each sweetening unit affected facility at onshore 

natural gas processing plants, you must demonstrate continuous 

compliance with the standards for SO2 specified in §60.5405(b) 

according to paragraphs (g)(1) and (2) of this section.

(1) The minimum required SO2 emission reduction efficiency 

(Zc) is compared to the emission reduction efficiency (R) 

achieved by the sulfur recovery technology.

(i) If R ≥ Zc, your affected facility is in compliance.

(ii) If R < Zc, your affected facility is not in compliance.
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(2) The emission reduction efficiency (R) achieved by the 

sulfur reduction technology must be determined using the 

procedures in §60.5406(c)(1).

§60.5416 What are the initial and continuous cover and closed 

vent system inspection and monitoring requirements for my 

storage vessel, centrifugal compressor and reciprocating 

compressor affected facilities?

For each closed vent system or cover at your storage 

vessel, centrifugal compressor or reciprocating compressor

affected facility, you must comply with the applicable 

requirements of paragraphs (a) through(c) of this section.

(a) Inspections for closed vent systems and covers 

installed on each centrifugal compressor or reciprocating 

compressor affected facility. Except as provided in paragraphs

(b)(11) and (12) of this section, you must inspect each closed 

vent system according to the procedures and schedule specified 

in paragraphs (a)(1) and (2) of this section, inspect each cover 

according to the procedures and schedule specified in paragraph 

(a)(3) of this section, and inspect each bypass device according 

to the procedures of paragraph (a)(4) of this section.

(1) For each closed vent system joint, seam, or other 

connection that is permanently or semi-permanently sealed (e.g., 
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a welded joint between two sections of hard piping or a bolted 

and gasketed ducting flange), you must meet the requirements 

specified in paragraphs (a)(1)(i) and (ii) of this section.

(i) Conduct an initial inspection according to the test 

methods and procedures specified in paragraph (b) of this 

section to demonstrate that the closed vent system operates with 

no detectable emissions. You must maintain records of the 

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

(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) For closed vent system components other than those 

specified in paragraph (a)(1) of this section, you must meet the 

requirements of paragraphs (a)(2)(i) through (iii) of this 

section.
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(i) Conduct an initial inspection according to the test 

methods and procedures specified in paragraph (b) of this 

section to demonstrate that the closed vent system operates with 

no detectable emissions. You must maintain records of the 

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

(ii) Conduct annual inspections according to the test 

methods and procedures specified in paragraph (b) of this 

section to demonstrate that the components or connections 

operate with no detectable emissions. You must maintain records 

of the inspection results as specified in §60.5420(c)(6).

(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) For each cover, you must meet the requirements in 

paragraphs (a)(3)(i) and (ii) of this section.

(i) Conduct visual 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 
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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.

(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).

(4) For each bypass device, except as provided for in 

§60.5411, you must meet the requirements of paragraphs (a)(4)(i) 

or (ii) of this section.

(i) Set the flow indicator to take a reading at least once 

every 15 minutes at the inlet to the bypass device that could 

divert the steam 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 
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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).

(b) No detectable emissions test methods and procedures. If 

you are required to conduct an inspection of a closed vent 

system or cover at your centrifugal compressor or reciprocating

compressor affected facility as specified in paragraphs (a)(1), 

(2), or (3) of this section, you must meet the requirements of 

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

(1) You must conduct the no detectable emissions test 

procedure in accordance with Method 21 at 40 CFR part 60, 

appendix A-7.

(2) The detection instrument must meet the performance 

criteria of Method 21 at 40 CFR part 60, appendix A-7, except 

that the instrument response factor criteria in section 3.1.2(a) 

of Method 21 must be for the average composition of the fluid 

and not for each individual organic compound in the stream.

(3) You must calibrate the detection instrument before use 

on each day of its use by the procedures specified in Method 21 

at 40 CFR part 60, appendix A-7.
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(4) Calibration gases must be as specified in paragraphs 

(b)(4)(i) and (ii) of this section.

(i) Zero air (less than 10 parts per million by volume 

hydrocarbon in air).

(ii) A mixture of methane in air at a concentration less 

than 10,000 parts per million by volume.

(5) You may choose to adjust or not adjust the detection 

instrument readings to account for the background organic 

concentration level. If you choose to adjust the instrument 

readings for the background level, you must determine the 

background level value according to the procedures in Method 21 

at 40 CFR part 60, appendix A-7.

(6) Your detection instrument must meet the performance 

criteria specified in paragraphs (b)(6)(i) and (ii) of this

section.

(i) Except as provided in paragraph (b)(6)(ii) of this 

section, the detection instrument must meet the performance 

criteria of Method 21 at 40 CFR part 60, appendix A-7, except 

the instrument response factor criteria in section 3.1.2(a) of 

Method 21 must be for the average composition of the process 

fluid, not each individual volatile organic compound in the 

stream. For process streams that contain nitrogen, air, or other 

inerts that are not organic hazardous air pollutants or volatile 
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organic compounds, you must calculate the average stream 

response factor on an inert-free basis.

(ii) If no instrument is available that will meet the 

performance criteria specified in paragraph (b)(6)(i) of this 

section, you may adjust the instrument readings by multiplying 

by the average response factor of the process fluid, calculated 

on an inert-free basis, as described in paragraph (b)(6)(i) of 

this section.

(7) You must determine if a potential leak interface 

operates with no detectable emissions using the applicable 

procedure specified in paragraph (b)(7)(i) or (ii) of this 

section.

(i) If you choose not to adjust the detection instrument 

readings for the background organic concentration level, then 

you must directly compare the maximum organic concentration

value measured by the detection instrument to the applicable 

value for the potential leak interface as specified in paragraph 

(b)(8) of this section.

(ii) If you choose to adjust the detection instrument 

readings for the background organic concentration level, you 

must compare the value of the arithmetic difference between the 

maximum organic concentration value measured by the instrument 

and the background organic concentration value as determined in 
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paragraph (b)(5) of this section with the applicable value for 

the potential leak interface as specified in paragraph (b)(8) of 

this section.

(8) A potential leak interface is determined to operate 

with no detectable organic emissions if the organic 

concentration value determined in paragraph (b)(7) of this 

section is less than 500 parts per million by volume.

(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.

(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 15 calendar 

days after the leak is detected.

(10) 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.
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(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.

(12) 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 (b)(12)(i) and (ii)

of this section are met. Difficult to inspect parts are exempt 

from the inspection requirements of paragraphs (a)(1) through 

(3) 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.
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(ii) You have a written plan that requires inspection of 

the equipment at least once every 5 years.

(13) Records. Records shall be maintained as specified in 

this section and in §60.5420(c)(9).

(c) Cover and closed vent system inspections for storage 

vessel affected facilities. If you install a control device or 

route emissions to a process, 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 (7) 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; 
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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.
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(3) For each bypass device, except as provided for in 

§60.5411(c)(3)(ii), 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 or process to the atmosphere. You must 

maintain records of each time the alarm is sounded according to 

§60.5420(c)(8).

(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 and records 

of each time the key is checked out, if applicable, 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 section, except as provided in 

paragraph (c)(5) of this section.
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(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 
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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.

§60.5417 What are the continuous control device monitoring 

requirements for my storage vessel or centrifugal compressor 

affected facility?

You must meet the applicable requirements of this section 

to demonstrate continuous compliance for each control device 
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used to meet emission standards for your 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.

(1) A boiler or process heater in which all vent streams 

are introduced with the primary fuel or is used as the primary 

fuel.

(2) A boiler or process heater with a design heat input 

capacity equal to or greater than 44 megawatts.

(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.
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(1) Each continuous parameter monitoring system must 

measure data values at least once every hour and record the 

parameters in paragraphs (c)(1)(i) or (ii) of this section.

(i) Each measured data value.

(ii) Each block average value for each 1-hour period or 

shorter periods calculated from all measured data values during 

each period. If values are measured more frequently than once 

per minute, a single value for each minute may be used to 

calculate the hourly (or shorter period) block average instead 

of all measured values.

(2) You must prepare a site-specific monitoring plan that 

addresses the monitoring system design, data collection, and the 

quality assurance and quality control elements outlined in 

paragraphs (c)(2)(i) through (v) of this section. You must 

install, calibrate, operate, and maintain each continuous 

parameter monitoring system in accordance with the procedures in 

your approved site-specific monitoring plan. 

(i) The performance criteria and design specifications for 

the monitoring system equipment, including the sample interface, 

detector signal analyzer, and data acquisition and calculations.

(ii) Sampling interface (e.g., thermocouple) location such 

that the monitoring system will provide representative 

measurements. 
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(iii) Equipment performance checks, system accuracy audits, 

or other audit procedures.

(iv) Ongoing operation and maintenance procedures in 

accordance with provisions in §60.13(b).

(v) Ongoing reporting and recordkeeping procedures in 

accordance with provisions in §60.7(c), (d), and (f).

(3) You must conduct the continuous parameter monitoring 

system equipment performance checks, system accuracy audits, or 

other audit procedures specified in the site-specific monitoring 

plan at least once every 12 months.

(4) You must conduct a performance evaluation of each 

continuous parameter monitoring system in accordance with the 

site-specific monitoring plan.

(d) You must install, calibrate, operate, and maintain a 

device equipped with a continuous recorder to measure the values 

of operating parameters appropriate for the control device as 

specified in either paragraph (d)(1), (2), or (3) of this 

section.

(1) A continuous monitoring system that measures the 

operating parameters in paragraphs (d)(1)(i) through (viii) of 

this section, as applicable.

(i) For a thermal vapor incinerator that demonstrates 

during the performance test conducted under §60.5413 that 
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combustion zone temperature is an accurate indicator of 

performance, a temperature monitoring device equipped with a 

continuous recorder. The monitoring device must have a minimum 

accuracy of ±1 percent of the temperature being monitored in °C, 

or ±2.5°C, whichever value is greater. You must install the 

temperature sensor at a location representative of the 

combustion zone temperature.

(ii) For a catalytic vapor incinerator, a temperature 

monitoring device equipped with a continuous recorder. The 

device must be capable of monitoring temperature at two 

locations and have a minimum accuracy of ±1 percent of the 

temperature being monitored in °C, or ±2.5°C, whichever value is 

greater. You must install one temperature sensor in the vent 

stream at the nearest feasible point to the catalyst bed inlet, 

and you must install a second temperature sensor in the vent 

stream at the nearest feasible point to the catalyst bed outlet.

(iii) For a flare, a heat sensing monitoring device 

equipped with a continuous recorder that indicates the 

continuous ignition of the pilot flame.

(iv) For a boiler or process heater, a temperature 

monitoring device equipped with a continuous recorder. The 

temperature monitoring device must have a minimum accuracy of ±1 

percent of the temperature being monitored in °C, or ±2.5°C, 
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whichever value is greater. You must install the temperature 

sensor at a location representative of the combustion zone 

temperature.

(v) For a condenser, a temperature monitoring device 

equipped with a continuous recorder. The temperature monitoring 

device must have a minimum accuracy of ±1 percent of the 

temperature being monitored in °C, or ±2.8°C, whichever value is 

greater. You must install the temperature sensor at a location 

in the exhaust vent stream from the condenser.

(vi) For a regenerative-type carbon adsorption system, a 

continuous monitoring system that meets the specifications in 

paragraphs (d)(1)(vi)(A) and (B) of this section. 

(A) The continuous parameter monitoring system must measure 

and record the average total regeneration stream mass flow or 

volumetric flow during each carbon bed regeneration cycle. The 

flow sensor must have a measurement sensitivity of 5 percent of 

the flow rate or 10 cubic feet per minute, whichever is greater. 

You must check the mechanical connections for leakage at least 

every month, and you must perform a visual inspection at least 

every 3 months of all components of the flow continuous 

parameter monitoring system for physical and operational 

integrity and all electrical connections for oxidation and 
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galvanic corrosion if your flow continuous parameter monitoring 

system is not equipped with a redundant flow sensor; and

(B) The continuous parameter monitoring system must measure 

and record the average carbon bed temperature for the duration 

of the carbon bed steaming cycle and measure the actual carbon 

bed temperature after regeneration and within 15 minutes of 

completing the cooling cycle. The temperature monitoring device 

must have a minimum accuracy of ±1 percent of the temperature

being monitored in °C, or ±2.5°C, whichever value is greater.

(vii) For a nonregenerative-type carbon adsorption system, 

you must monitor the design carbon replacement interval 

established using a performance test performed as specified in 

§60.5413(b). The design carbon replacement interval must be 

based on the total carbon working capacity of the control device 

and source operating schedule.

(viii) For a combustion control device whose model is 

tested under §60.5413(d), a continuous monitoring system meeting 

the requirements of paragraphs (d)(1)(viii)(A) and (B) of this 

section.

(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 
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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.

(3) A continuous monitoring system that measures operating 

parameters other than those specified in paragraph (d)(1) or (2) 

of this section, upon approval of the Administrator as specified 

in §60.13(i).

(e) You must calculate the daily average value for each 

monitored operating parameter for each operating day, using the 

data recorded by the monitoring system, except for inlet gas 

flow rate. If the emissions unit operation is continuous, the 

operating day is a 24-hour period. If the emissions unit 

operation is not continuous, the operating day is the total 

number of hours of control device operation per 24-hour period. 

Valid data points must be available for 75 percent of the 
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operating hours in an operating day to compute the daily 

average.

(f) For each operating parameter monitor installed in 

accordance with the requirements of paragraph (d) of this 

section, you must comply with paragraph (f)(1) of this section 

for all control devices. When condensers are installed, you must 

also comply with paragraph (f)(2) of this section.

(1) You must establish a minimum operating parameter value 

or a maximum operating parameter value, as appropriate for the 

control device, to define the conditions at which the control 

device must be operated to continuously achieve the applicable 

performance requirements of §60.5412(a). You must establish each 

minimum or maximum operating parameter value as specified in 

paragraphs (f)(1)(i) through (iii) of this section.

(i) If you conduct performance tests in accordance with the 

requirements of §60.5413(b) to demonstrate that the control 

device achieves the applicable performance requirements 

specified in §60.5412(a), then you must establish the minimum 

operating parameter value or the maximum operating parameter 

value based on values measured during the performance test and 

supplemented, as necessary, by a condenser design analysis or 

control device manufacturer recommendations or a combination of 

both.
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(ii) If you use a condenser design analysis in accordance 

with the requirements of §60.5413(c) to demonstrate that the 

control device achieves the applicable performance requirements 

specified in §60.5412(a), then you must establish the minimum 

operating parameter value or the maximum operating parameter 

value based on the condenser design analysis and supplemented, 

as necessary, by the condenser manufacturer's recommendations.

(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.

(2) If you use a condenser as specified in paragraph 

(d)(1)(v) of this section, you must establish a condenser 

performance curve showing the relationship between condenser 

outlet temperature and condenser control efficiency, according 

to the requirements of paragraphs (f)(2)(i) and (ii) of this 

section .

(i) If you conduct a performance test in accordance with 

the requirements of §60.5413(b) to demonstrate that the 

condenser achieves the applicable performance requirements in 

§60.5412(a), then the condenser performance curve must be based 
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on values measured during the performance test and supplemented 

as necessary by control device design analysis, or control 

device manufacturer's recommendations, or a combination or both.

(ii) If you use a control device design analysis in 

accordance with the requirements of §60.5413(c)(1) to 

demonstrate that the condenser achieves the applicable 

performance requirements specified in §60.5412(a), then the 

condenser performance curve must be based on the condenser 

design analysis and supplemented, as necessary, by the control 

device manufacturer's recommendations.

(g) A deviation for a given control device is determined to 

have occurred when the monitoring data or lack of monitoring 

data result in any one of the criteria specified in paragraphs 

(g)(1) through (g)(6) of this section being met. If you monitor 

multiple operating parameters for the same control device during 

the same operating day and more than one of these operating 

parameters meets a deviation criterion specified in paragraphs 

(g)(1) through (6) of this section, then a single excursion is 

determined to have occurred for the control device for that 

operating day.

(1) A deviation occurs when the daily average value of a 

monitored operating parameter is less than the minimum operating 

parameter limit (or, if applicable, greater than the maximum 
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operating parameter limit) established in paragraph (f)(1) of 

this section.

(2) If you meet §60.5412(a)(2), a deviation occurs when the 

365-day average condenser efficiency calculated according to the 

requirements specified in §60.5415(e)(8)(iv) is less than 95.0 

percent. 

(3) If you meet §60.5412(a)(2) and you have less than 365 

days of data, a deviation occurs when the average condenser 

efficiency calculated according to the procedures specified in 

§60.5415(e)(8)(iv)(A) or (B) is less than 90.0 percent. 

(4) A deviation occurs when the monitoring data are not 

available for at least 75 percent of the operating hours in a 

day.

(5) 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, a 

deviation occurs when the requirements of paragraphs (g)(5)(i) 

and (ii) of this section are met.

(i) For each bypass line subject to §60.5411(a)(3)(i)(A), 

the flow indicator indicates that flow has been detected and 

that the stream has been diverted away from the control device 

to the atmosphere.
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(ii) For each bypass line subject to §60.5411(a)(3)(i)(B), 

if the seal or closure mechanism has been broken, the bypass 

line valve position has changed, the key for the lock-and-key 

type lock has been checked out, or the car-seal has broken.

(6) For a combustion control device whose model is tested 

under §60.5413(d), a deviation occurs when the conditions of 

paragraphs (g)(6)(i) or (ii) are met.

(i) The inlet gas flow rate exceeds the maximum established 

during the test conducted under §60.5413(d).

(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 
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(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 observed, you must clear the obstruction as soon 

as practicable.
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(B) You must check for liquid reaching the 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 available for inspection as 

specified in §60.5420(c)(13).

§60.5420 What are my notification, reporting, and recordkeeping 

requirements?

(a) You must submit the notifications according to 

paragraphs (a)(1) and (2) 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 
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vessel affected facility you are not required to submit the 

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

(2)(i) If you own or operate a gas well affected facility, 

you must submit a notification to the Administrator no later 

than 2 days prior to the commencement of each well completion 

operation listing the anticipated date of the well completion 

operation. The notification shall include contact information 

for the owner or operator; the API well number, the latitude and 

longitude coordinates for each well in decimal degrees to an 

accuracy and precision of five (5) decimals of a degree using 

the North American Datum of 1983; and the planned date of the 

beginning of flowback. You may submit the notification in 

writing or in electronic format.

(ii) If you are subject to state regulations that require 

advance notification of well completions and you have met those 

notification requirements, then you are considered to have met 

the advance notification requirements of paragraph (a)(2)(i) of 

this section.

(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
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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. 

(1) The general information specified in paragraphs 

(b)(1)(i) through (iv) of this section.

(i) The company name and address of the affected facility. 

(ii) An identification of each affected facility being 

included in the annual report.

(iii) Beginning and ending dates of the reporting period.

(iv) A certification by a certifying official of truth, 

accuracy, and completeness. This certification shall state that, 

based on information and belief formed after reasonable inquiry, 

the statements and information in the document are true, 

accurate, and complete.
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(2) For each gas well affected facility, the information in 

paragraphs (b)(2)(i) through (ii) of this section.

(i) Records of each well completion operation as specified 

in paragraph (c)(1)(i) through (iv) of this section for each gas 

well affected facility conducted during the reporting period. In 

lieu of submitting the records specified in paragraph (c)(1)(i) 

through (iv), the owner or operator may submit a list of the 

well completions with hydraulic fracturing completed during the 

reporting period and the records required by paragraph (c)(1)(v) 

of this section for each well completion.

(ii) Records of deviations specified in paragraph 

(c)(1)(ii) of this section that occurred during the reporting 

period. 

(3) For each centrifugal compressor affected facility, the 

information specified in paragraphs (b)(3)(i) and (ii) of this 

section.

(i) An identification of each centrifugal compressor using 

a wet seal system constructed, modified or reconstructed during 

the reporting period.

(ii) Records of deviations specified in paragraph (c)(2) of 

this section that occurred during the reporting period.
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(iii) If required to comply with §60.5380(a)(1), the 

records specified in paragraphs (c)(6) through (11) of this 

section.

(4) For each reciprocating compressor affected facility, 

the information specified in paragraphs (b)(4)(i) through (ii) 

of this section.

(i) The cumulative number of hours of operation or the 

number of months since initial startup, since October 15, 2012, 

or since the previous reciprocating compressor rod packing 

replacement, whichever is later.

(ii) Records of deviations specified in paragraph 

(c)(3)(iii) of this section that occurred during the reporting 

period.

(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 (c)(2).

(ii) If applicable, documentation that the use of pneumatic 

controller affected facilities with a natural gas bleed rate 
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greater than 6 standard cubic feet per hour are required and the 

reasons why.

(iii) Records of deviations specified in paragraph 

(c)(4)(v) of this section that occurred during the reporting 

period.

(6) For each storage vessel affected facility, the 

information in paragraphs (b)(6)(i) through (vii) of this 

section.

(i) An identification, including the location, of each 

storage vessel affected facility for which construction, 

modification or reconstruction commenced 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 §60.5365(e) for each storage vessel that became an 

affected facility during the reporting period or is returned to 

service during the reporting period.

(iii) Records of deviations specified in paragraph 

(c)(5)(iii) of this section that occurred during the reporting 

period.
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(iv) You must submit a notification identifying each Group 

1 storage vessel affected facility in your initial annual 

report. You must include 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.

(v) A statement that you have met the requirements 

specified in §60.5410(h)(2) and (3).

(vi) You must identify each storage vessel affected 

facility that is removed from service during the reporting 

period as specified in §60.5395(f)(1)(ii), including the date 

the storage vessel affected facility was removed from service.

(vii) You must identify each storage vessel affected 

facility returned to service during the reporting period as 

specified in §60.5395(f)(3), including the date the storage 

vessel affected facility was returned to service.

(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 
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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 website 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/OAPQS/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 
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conducted using test methods that are not listed on the ERT 

website, 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 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 website: 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 (13) of this section. All records required by 

this subpart must be maintained either onsite or at the nearest

local field office for at least 5 years.
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(1) The records for each gas well affected facility as 

specified in paragraphs (c)(1)(i) through (v) of this section.

(i) Records identifying each well completion operation for 

each gas well affected facility;

(ii) Records of deviations in cases where well completion 

operations with hydraulic fracturing were not performed in 

compliance with the requirements specified in §60.5375.

(iii) Records required in §60.5375(b) or (f) for each well 

completion operation conducted for each gas well affected 

facility that occurred during the reporting period. You must 

maintain the records specified in paragraphs (c)(1)(iii)(A) and

(B) of this section.

(A) For each gas well affected facility required to comply 

with the requirements of §60.5375(a), you must record: The 

location of the well; the API well number; the date and time of 

the onset of flowback following hydraulic fracturing or 

refracturing; the date and time that flowback was directed to a 

separator as required in §60.5375(a)(1)(i); the date and time of 

each occurrence of returning to the initial flowback stage under 

§60.5375(a)(1)(i); and the date and time that the well was shut 

in and the flowback equipment was permanently disconnected, or 

the startup of production; the duration of flowback; duration of 

recovery to the flow line; duration of combustion; duration of 
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venting; and specific reasons for venting in lieu of capture or 

combustion. The duration must be specified in hours of time.

(B) For each gas well affected facility required to comply 

with the requirements of §60.5375(f), you must maintain the 

records specified in paragraph (c)(1)(iii)(A) of this section 

except that you do not have to record the duration of recovery 

to the flow line. 

(iv) For each gas well facility for which you claim an 

exception under §60.5375(a)(3), you must record: the location of 

the well; the API well number; the specific exception claimed; 

the starting date and ending date for the period the well 

operated under the exception; and an explanation of why the well 

meets the claimed exception.

(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).

(2) For each centrifugal compressor affected facility, you 

must maintain records of deviations in cases where the 

centrifugal compressor was not operated in compliance with the 

requirements specified in §60.5380.
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(3) For each reciprocating compressors affected facility, 

you must maintain the records in paragraphs (c)(3)(i) through

(iii) of this section.

(i) Records of the cumulative number of hours of operation

or number of months since initial startup or October 15, 2012,

or the previous replacement of the reciprocating compressor rod 

packing, whichever is later.

(ii) Records of the date and time of each reciprocating 

compressor rod packing replacement, or date of installation of a 

rod packing emissions collection system and closed vent system 

as specified in §60.5385(a)(3).

(iii) Records of deviations in cases where the 

reciprocating compressor was not operated in compliance with the 

requirements specified in §60.5385.

(4) For each pneumatic controller affected facility, you 

must maintain the records identified in paragraphs (c)(4)(i) 

through (v) of this section.

(i) Records of the date, location and manufacturer 

specifications for each pneumatic controller constructed, 

modified or reconstructed.

(ii) Records of the demonstration that the use of pneumatic 

controller affected facilities with a natural gas bleed rate 
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greater than the applicable standard are required and the 

reasons why.

(iii) If the pneumatic controller is not located at a 

natural gas processing plant, records of the manufacturer’s 

specifications indicating that the controller is designed such 

that natural gas bleed rate is less than or equal to 6 standard 

cubic feet per hour.

(iv) If the pneumatic controller is located at a natural 

gas processing plant, records of the documentation that the 

natural gas bleed rate is zero.

(v) Records of deviations in cases where the pneumatic 

controller was not operated in compliance with the requirements 

specified in §60.5390.

(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.

(i) If required to reduce emissions by complying with 

§60.5395(d)(1), the records specified in §§60.5420(c)(6) through 

(c)(8), §60.5416(c)(6)(ii), and §60.6516(c)(7)(ii) of this 

subpart.

(ii) Records of each VOC emissions determination for each 

storage vessel affected facility made under §60.5365(e)
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including identification of the model or calculation methodology 

used to calculate the VOC emission rate.

(iii) Records of deviations in cases where the storage 

vessel was not operated in compliance with the requirements 

specified in §§60.5395, 60.5411, 60.5412, and 60.5413, as 

applicable.

(iv) For storage vessels that are skid-mounted or 

permanently attached to something that is mobile (such as 

trucks, railcars, barges or ships), records indicating the 

number of consecutive days that the vessel is located at a site 

in the oil and natural gas production segment, natural gas 

processing segment or natural gas transmission and storage 

segment. If a storage vessel is removed from a site and, within 

30 days, is either returned to or replaced by another storage 

vessel at the site to serve the same or similar function, then 

the entire period since the original storage vessel was first 

located at the site, including the days when the storage vessel 

was removed, will be added to the count towards the number of 

consecutive days.

(v) You must maintain records of the identification and 

location of each storage vessel affected facility. (6) 

Records of each closed vent system inspection required under 
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§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 or reciprocating compressors or

§60.5416(c)(2) for storage vessels.

(8) If you are subject to the bypass requirements of 

§60.5416(a)(4) for centrifugal or reciprocating compressors or

§60.5416(c)(3) for storage vessels, a record of each inspection 

or a record each time the key is checked out or a record of each 

time the alarm is sounded. 

(9) If you are subject to the closed vent system no 

detectable emissions requirements of §60.5416(b) for centrifugal

or reciprocating compressors, a record of the monitoring 

conducted in accordance with §60.5416(b).

(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 
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continuous parameter monitoring system data, results of all 

compliance calculations, and results of all inspections.

(12) 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).

(13) 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 operating 

instructions, procedures and maintenance schedule must be 

available for inspection.
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§60.5421 What are my additional recordkeeping requirements for 

my affected facility subject to VOC requirements for onshore 

natural gas processing plants?

(a) You must comply with the requirements of paragraph (b) 

of this section in addition to the requirements of §60.486a.

(b) The following recordkeeping requirements apply to 

pressure relief devices subject to the requirements of 

§60.5401(b)(1) of this subpart.

(1) When each leak is detected as specified in 

§60.5401(b)(2), a weatherproof and readily visible 

identification, marked with the equipment identification number, 

must be attached to the leaking equipment. The identification on 

the pressure relief device may be removed after it has been 

repaired.

(2) When each leak is detected as specified in 

§60.5401(b)(2), the following information must be recorded in a 

log and shall be kept for 2 years in a readily accessible 

location:

(i) The instrument and operator identification numbers and 

the equipment identification number.

(ii) The date the leak was detected and the dates of each 

attempt to repair the leak.
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(iii) Repair methods applied in each attempt to repair the 

leak.

(iv) ”Above 500 ppm” if the maximum instrument reading 

measured by the methods specified in paragraph (a) of this 

section after each repair attempt is 500 ppm or greater.

(v) ”Repair delayed” and the reason for the delay if a leak 

is not repaired within 15 calendar days after discovery of the 

leak.

(vi) The signature of the owner or operator (or designate) 

whose decision it was that repair could not be effected without 

a process shutdown.

(vii) The expected date of successful repair of the leak if 

a leak is not repaired within 15 days.

(viii) Dates of process unit shutdowns that occur while the 

equipment is unrepaired.

(ix) The date of successful repair of the leak.

(x) A list of identification numbers for equipment that are 

designated for no detectable emissions under the provisions of 

§60.482-4a(a). The designation of equipment subject to the 

provisions of §60.482-4a(a) must be signed by the owner or 

operator.
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§60.5422 What are my additional reporting requirements for my 

affected facility subject to VOC requirements for onshore 

natural gas processing plants?

(a) You must comply with the requirements of paragraphs (b) 

and (c) of this section in addition to the requirements of 

§60.487a(a), (b), (c)(2)(i) through (iv), and (c)(2)(vii) 

through (viii).

(b) An owner or operator must include the following 

information in the initial semiannual report in addition to the 

information required in §60.487a(b)(1) through (4): Number of 

pressure relief devices subject to the requirements of 

§60.5401(b) except for those pressure relief devices designated 

for no detectable emissions under the provisions of §60.482–

4a(a) and those pressure relief devices complying with §60.482–

4a(c).

(c) An owner or operator must include the following 

information in all semiannual reports in addition to the 

information required in §60.487a(c)(2)(i) through (vi):

(1) Number of pressure relief devices for which leaks were 

detected as required in §60.5401(b)(2); and

(2) Number of pressure relief devices for which leaks were 

not repaired as required in §60.5401(b)(3).
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§60.5423 What additional recordkeeping and reporting 

requirements apply to my sweetening unit affected facilities at 

onshore natural gas processing plants?

(a) You must retain records of the calculations and 

measurements required in §60.5405(a) and (b) and §60.5407(a) 

through (g) for at least 2 years following the date of the 

measurements. This requirement is included under §60.7(d) of the 

General Provisions.

(b) You must submit a report of excess emissions to the 

Administrator in your annual report if you had excess emissions 

during the reporting period. For the purpose of these reports, 

excess emissions are defined as:

(1) Any 24-hour period (at consistent intervals) during 

which the average sulfur emission reduction efficiency (R) is 

less than the minimum required efficiency (Z).

(2) For any affected facility electing to comply with the 

provisions of §60.5407(b)(2), any 24-hour period during which 

the average temperature of the gases leaving the combustion zone 

of an incinerator is less than the appropriate operating 

temperature as determined during the most recent performance 

test in accordance with the provisions of §60.5407(b)(2). Each 

24-hour period must consist of at least 96 temperature 

measurements equally spaced over the 24 hours.
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(c) To certify that a facility is exempt from the control 

requirements of these standards, for each facility with a design 

capacity less that 2 LT/D of H2S in the acid gas (expressed as 

sulfur) you must keep, for the life of the facility, an analysis 

demonstrating that the facility's design capacity is less than 2 

LT/D of H2S expressed as sulfur.

(d) If you elect to comply with §60.5407(e) you must keep, 

for the life of the facility, a record demonstrating that the 

facility's design capacity is less than 150 LT/D of H2S expressed 

as sulfur.

(e) The requirements of paragraph (b) of this section 

remain in force until and unless the EPA, in delegating 

enforcement authority to a state under section 111(c) of the 

Act, approves reporting requirements or an alternative means of 

compliance surveillance adopted by such state. In that event, 

affected sources within the state will be relieved of obligation 

to comply with paragraph (b) of this section, provided that they 

comply with the requirements established by the state.

§60.5425 What part of the General Provisions apply to me?

Table 3 to this subpart shows which parts of the General 

Provisions in §§60.1 through 60.19 apply to you.

§60.5430 What definitions apply to this subpart?
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As used in this subpart, all terms not defined herein shall 

have the meaning given them in the Act, in subpart A or subpart 

VVa of part 60; and the following terms shall have the specific 

meanings given them.

Acid gas means a gas stream of hydrogen sulfide (H2S) and 

carbon dioxide (CO2) that has been separated from sour natural 

gas by a sweetening unit.

Alaskan North Slope means the approximately 69,000 squaremile area extending from the Brooks Range to the Arctic Ocean.

API Gravity means the weight per unit volume of hydrocarbon 

liquids as measured by a system recommended by the American 

Petroleum Institute (API) and is expressed in degrees.

Bleed rate means the rate in standard cubic feet per hour 

at which natural gas is continuously vented (bleeds) from a 

pneumatic controller.

Centrifugal compressor means any machine for raising the 

pressure of a natural gas by drawing in low pressure natural gas 

and discharging significantly higher pressure natural gas by 

means of mechanical rotating vanes or impellers. Screw, sliding 

vane, and liquid ring compressors are not centrifugal 

compressors for the purposes of this subpart.

Certifying official means one of the following:
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(1) For a corporation: a president, secretary, treasurer, 

or vice-president of the corporation in charge of a principal 

business function, or any other person who performs similar 

policy or decision-making functions for the corporation, or a 

duly authorized representative of such person if the 

representative is responsible for the overall operation of one 

or more manufacturing, production, or operating facilities 

applying for or subject to a permit and either:

(i) The facilities employ more than 250 persons or have 

gross annual sales or expenditures exceeding $25 million (in 

second quarter 1980 dollars); or

(ii) The Administrator is notified of such delegation of 

authority prior to the exercise of that authority. The 

Administrator reserves the right to evaluate such delegation;

(2) For a partnership (including but not limited to general 

partnerships, limited partnerships, and limited liability 

partnerships) or sole proprietorship: a general partner or the 

proprietor, respectively. If a general partner is a corporation, 

the provisions of paragraph (1) of this definition apply;

(3) For a municipality, State, Federal, or other public 

agency: Either a principal executive officer or ranking elected 

official. For the purposes of this part, a principal executive 

officer of a Federal agency includes the chief executive officer 
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having responsibility for the overall operations of a principal 

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

EPA); or

(4) For affected facilities:

(i) The designated representative in so far as actions, 

standards, requirements, or prohibitions under title IV of the 

Clean Air Act or the regulations promulgated thereunder are 

concerned; or

(ii) The designated representative for any other purposes 

under part 60.

City gate means the delivery point at which natural gas is 

transferred from a transmission pipeline to the local gas 

utility.

Collection system means any infrastructure that conveys gas 

or liquids from the well site to another location for treatment, 

storage, processing, recycling, disposal or other handling.

Completion combustion device means any ignition device, 

installed horizontally or vertically, used in exploration and 

production operations to combust otherwise vented emissions from 

completions.

Compressor station means any permanent combination of one 

or more compressors that move natural gas at increased pressure 

from fields, in transmission pipelines, or into storage.
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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.

Continuous bleed means a continuous flow of pneumatic 

supply natural gas to the process control device (e.g., level 

control, temperature control, pressure control) where the supply 

gas pressure is modulated by the process condition, and then 

flows to the valve controller where the signal is compared with 

the process set-point to adjust gas pressure in the valve 

actuator.

Custody transfer means the transfer of natural gas after 

processing and/or treatment in the producing operations, or from 

storage vessels or automatic transfer facilities or other such 

equipment, including product loading racks, to pipelines or any 

other forms of transportation.

Dehydrator means a device in which an absorbent directly 

contacts a natural gas stream and absorbs water in a contact 

tower or absorption column (absorber).

Deviation means any instance in which an affected source 

subject to this subpart, or an owner or operator of such a 

source:
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(1) Fails to meet any requirement or obligation established 

by this subpart including, but not limited to, any emission 

limit, operating limit, or work practice standard;

(2) Fails to meet any term or condition that is adopted to 

implement an applicable requirement in this subpart and that is 

included in the operating permit for any affected source 

required to obtain such a permit; or

(3) Fails to meet any emission limit, operating limit, or 

work practice standard in this subpart during startup, shutdown, 

or malfunction, regardless of whether or not such failure is 

permitted by this subpart.

Delineation well means a well drilled in order to determine 

the boundary of a field or producing reservoir.

Equipment, as used in the standards and requirements in 

this subpart relative to the equipment leaks of VOC from onshore 

natural gas processing plants, means each pump, pressure relief

device, open-ended valve or line, valve, and flange or other 

connector that is in VOC service or in wet gas service, and any 

device or system required by those same standards and 

requirements in this subpart.

Field gas means feedstock gas entering the natural gas 

processing plant.
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Field gas gathering means the system used transport field 

gas from a field to the main pipeline in the area.

Flare means a thermal oxidation system using an open 

(without enclosure) flame. Completion combustion devices as 

defined in this section are not considered flares.

Flow line means a pipeline used to transport oil and/or gas 

to a processing facility, a mainline pipeline, re-injection, or 

routed to a process or other useful purpose.

Flowback means the process of allowing fluids and entrained 

solids to flow from a natural gas well following a treatment, 

either in preparation for a subsequent phase of treatment or in 

preparation for cleanup and returning the well to production.

The term flowback also means the fluids and entrained solids 

that emerge from a natural gas well during the flowback process. 

The flowback period begins when material introduced into the 

well during the treatment returns to the surface following 

hydraulic fracturing or refracturing. The flowback period ends 

when either the well is shut in and permanently disconnected 

from the flowback equipment or at the startup of production. The 

flowback period includes the initial flowback stage and the

separation flowback stage. 

Gas processing plant process unit means equipment assembled 

for the extraction of natural gas liquids from field gas, the 
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fractionation of the liquids into natural gas products, or other 

operations associated with the processing of natural gas 

products. A process unit can operate independently if supplied 

with sufficient feed or raw materials and sufficient storage 

facilities for the products.

Gas well or natural gas well means an onshore well drilled 

principally for production of natural gas.

Group 1 storage vessel means a storage vessel, as defined 

in this section, for which construction, modification or 

reconstruction has commenced after August 23, 2011, and on or 

before April 12, 2013.

Group 2 storage vessel means a storage vessel, as defined 

in this section, for which construction, modification or 

reconstruction has commenced after April 12, 2013. 

Hydraulic fracturing or refracturing means the process of 

directing pressurized fluids containing any combination of 

water, proppant, and any added chemicals to penetrate tight 

formations, such as shale or coal formations, that subsequently 

require high rate, extended flowback to expel fracture fluids 

and solids during completions. 

Hydraulic refracturing means conducting a subsequent 

hydraulic fracturing operation at a well that has previously 

undergone a hydraulic fracturing operation.
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Initial flowback stage means the period during a well 

completion operation which begins at the onset of flowback and 

ends at the beginning of the separation flowback stage. 

In light liquid service means that the piece of equipment 

contains a liquid that meets the conditions specified in 

§60.485a(e) or §60.5401(g)(2) of this part.

In wet gas service means that a compressor or piece of 

equipment contains or contacts the field gas before the 

extraction step at a gas processing plant process unit.

Intermediate hydrocarbon liquid means any naturally 

occurring, unrefined petroleum liquid.

Intermittent/snap-action pneumatic controller means a 

pneumatic controller that vents non-continuously.

Liquefied natural gas unit means a unit used to cool 

natural gas to the point at which it is condensed into a liquid 

which is colorless, odorless, non-corrosive and non-toxic. 

Low pressure gas well means a well with reservoir pressure 

and vertical well depth such that 0.445 times the reservoir 

pressure (in psia) minus 0.038 times the vertical well depth (in 

feet) minus 67.578 psia is less than the flow line pressure at 

the sales meter.
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Maximum average daily throughput means the earliest 

calculation of daily average throughput during the 30-day PTE

evaluation period employing generally accepted methods.

Natural gas-driven pneumatic controller means a pneumatic 

controller powered by pressurized natural gas.

Natural gas liquids means the hydrocarbons, such as ethane, 

propane, butane, and pentane that are extracted from field gas.

Natural gas processing plant (gas plant) means any 

processing site engaged in the extraction of natural gas liquids 

from field gas, fractionation of mixed natural gas liquids to 

natural gas products, or both. A Joule-Thompson valve, a dew 

point depression valve, or an isolated or standalone JouleThompson skid is not a natural gas processing plant. 

Natural gas transmission means the pipelines used for the 

long distance transport of natural gas (excluding processing). 

Specific equipment used in natural gas transmission includes the 

land, mains, valves, meters, boosters, regulators, storage 

vessels, dehydrators, compressors, and their driving units and 

appurtenances, and equipment used for transporting gas from a 

production plant, delivery point of purchased gas, gathering 

system, storage area, or other wholesale source of gas to one or 

more distribution area(s).
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Nonfractionating plant means any gas plant that does not 

fractionate mixed natural gas liquids into natural gas products.

Non-natural gas-driven pneumatic controller means an 

instrument that is actuated using other sources of power than 

pressurized natural gas; examples include solar, electric, and 

instrument air.

Onshore means all facilities except those that are located 

in the territorial seas or on the outer continental shelf.

Pneumatic controller means an automated instrument used for 

maintaining a process condition such as liquid level, pressure, 

delta-pressure and temperature.

Pressure vessel means a storage vessel that is used to 

store liquids or gases and is designed not to vent to the 

atmosphere as a result of compression of the vapor headspace in 

the pressure vessel during filling of the pressure vessel to its 

design capacity.

Process unit means components assembled for the extraction 

of natural gas liquids from field gas, the fractionation of the 

liquids into natural gas products, or other operations 

associated with the processing of natural gas products. A 

process unit can operate independently if supplied with 

sufficient feed or raw materials and sufficient storage 

facilities for the products. 
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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.

Reciprocating compressor means a piece of equipment that 

increases the pressure of a process gas by positive 

displacement, employing linear movement of the driveshaft.

Reciprocating compressor rod packing means a series of 

flexible rings in machined metal cups that fit around the 

reciprocating compressor piston rod to create a seal limiting 

the amount of compressed natural gas that escapes to the 

atmosphere.

Recovered gas means gas recovered through the separation 

process during flowback.

Recovered liquids means any crude oil, condensate or 

produced water recovered through the separation process during 

flowback.

Reduced sulfur compounds means H2S, carbonyl sulfide (COS), 

and carbon disulfide (CS2).

Removed from service means that a storage vessel affected 

facility has been physically isolated and disconnected from the 
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process for a purpose other than maintenance in accordance with 

§60.5395(f)(1).

Returned to service means that a Group 1 or Group 2 storage 

vessel affected facility that was removed from service has been 

(1) reconnected to the original source of liquids, connected in 

parallel to any storage vessel affected facility or has been 

used to replace any storage vessel affected facility; or (2) 

installed in any location covered by this subpart and introduced 

with crude oil, condensate, intermediate hydrocarbon liquids or 

produced water. 

Routed to a process or route to a process means the 

emissions are conveyed via a closed vent system to any enclosed 

portion of a process where the emissions are predominantly 

recycled and/or consumed in the same manner as a material that 

fulfills the same function in the process and/or transformed by 

chemical reaction into materials that are not regulated 

materials and/or incorporated into a product; and/or recovered.

Salable quality gas means natural gas that meets the flow 

line or collection system operator specifications, regardless of 

whether such gas is sold.

Separation flowback stage means the period during a well 

completion operation when it is technically feasible for a 

separator to function. The separation flowback stage ends at the 
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startup of production, or when the well is shut in and

permanently disconnected from the flowback equipment.

Startup of production means the beginning of initial flow 

following the end of flowback when there is continuous recovery 

of salable quality gas and separation and recovery of any crude 

oil, condensate or produced water.

Storage vessel means a tank or other vessel that contains

an accumulation of crude oil, condensate, intermediate 

hydrocarbon liquids, or produced water, and that is constructed 

primarily of nonearthen materials (such as wood, concrete, 

steel, fiberglass, or plastic) which provide structural support.

Two or more storage vessels connected in parallel are considered 

equivalent to a single storage vessel with throughput equal to 

the total throughput of the storage vessels connected in 

parallel. A well completion vessel that receives recovered 

liquids from a well after startup of production following 

flowback for a period which exceeds 60 days is considered a 

storage vessel under this subpart. A tank or other vessel shall 

not be considered a storage vessel if it has been removed from 

service in accordance with the requirements of §60.5395(f) until 

such time as such tank or other vessel has been returned to 

service. For the purposes of this subpart, the following are not 

considered storage vessels:
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(1) Vessels that are skid-mounted or permanently attached 

to something that is mobile (such as trucks, railcars, barges or 

ships), and are intended to be located at a site for less than 

180 consecutive days. If you do not keep or are not able to 

produce records, as required by §60.5420(c)(5)(iv), showing that 

the vessel has been located at a site for less than 180 

consecutive days, the vessel described herein is considered to 

be a storage vessel from the date the original vessel was first 

located at the site. This exclusion does not apply to a well 

completion vessel described above. 

(2) Process vessels such as surge control vessels, bottoms 

receivers or knockout vessels.

(3) Pressure vessels designed to operate in excess of 204.9 

kilopascals and without emissions to the atmosphere.

Sulfur production rate means the rate of liquid sulfur

accumulation from the sulfur recovery unit.

Sulfur recovery unit means a process device that recovers 

element sulfur from acid gas.

Surface site means any combination of one or more graded 

pad sites, gravel pad sites, foundations, platforms, or the 

immediate physical location upon which equipment is physically 

affixed.
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Sweetening unit means a process device that removes 

hydrogen sulfide and/or carbon dioxide from the sour natural gas 

stream. 

Total Reduced Sulfur (TRS) means the sum of the sulfur 

compounds hydrogen sulfide, methyl mercaptan, dimethyl sulfide, 

and dimethyl disulfide as measured by Method 16 of appendix A to 

part 60 of this chapter.

Total SO2 equivalents means the sum of volumetric or mass 

concentrations of the sulfur compounds obtained by adding the 

quantity existing as SO2 to the quantity of SO2 that would be 

obtained if all reduced sulfur compounds were converted to SO2

(ppmv or kg/dscm (lb/dscf)).

Underground storage vessel means a storage vessel stored 

below ground.

Well means an oil or gas well, a hole drilled for the 

purpose of producing oil or gas, or a well into which fluids are 

injected.

Well completion means the process that allows for the 

flowback of petroleum or natural gas from newly drilled wells to 

expel drilling and reservoir fluids and tests the reservoir flow 

characteristics, which may vent produced hydrocarbons to the 

atmosphere via an open pit or tank. 
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Well completion operation means any well completion with 

hydraulic fracturing or refracturing occurring at a gas well

affected facility.

Well completion vessel means a vessel that contains 

flowback during a well completion operation following hydraulic 

fracturing or refracturing. A well completion vessel may be a 

lined earthen pit, a tank or other vessel that is skid-mounted 

or portable. A well completion vessel that receives recovered 

liquids from a well after startup of production following 

flowback for a period which exceeds 60 days is considered a 

storage vessel under this subpart.

Well site means one or more areas that are directly 

disturbed during the drilling and subsequent operation of, or 

affected by, production facilities directly associated with any 

oil well, gas well, or injection well and its associated well 

pad.

Wellhead means the piping, casing, tubing and connected 

valves protruding above the earth’s surface for an oil and/or 

natural gas well. The wellhead ends where the flow line connects 

to a wellhead valve. The wellhead does not include other 

equipment at the well site except for any conveyance through 

which gas is vented to the atmosphere.
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Wildcat well means a well outside known fields or the first 

well drilled in an oil or gas field where no other oil and gas 

production exists. 

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 88.51X0.0101Y

0.0125 or 99.9, whichever is 

smaller

20<Y<50 79.0 88.51X

0.0101Y0.0125 or 97.9, whichever 

is smaller

97.9

10<Y<20 79.0 88.51X

0.0101Y0.0125

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 85.35X0.0144Y

0.0128 or 99.9, whichever is 

smaller

20<Y<50 74.0 85.35X0.0144Y

0.0128 or 97.5, whichever 

is smaller

97.5

10<Y<20 74.0 85.35X0.0144Y

0.0128

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.
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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.

Table 3 to Subpart OOOO of part 60 – Applicability of General 

Provisions to Subpart OOOO

As stated in §60.5425, you must comply with the following 

applicable General Provisions:

General

Provisions 

Citation Subject of Citation

Applies 

to

subpart? Explanation

§60.1

General 

applicability of 

the General 

Provisions

Yes

§60.2 Definitions Yes Additional terms 

defined in §60.5430

§60.3 Units and 

abbreviations

Yes

§60.4 Address Yes

§60.5 Determination of 

construction or 

modification

Yes

§60.6 Review of plans Yes

§60.7 Notification and 

record keeping

Yes Except that §60.7 

only applies as 

specified in 

§60.5420(a).

§60.8 Performance tests Yes Performance testing 

is required for 

control devices 

used on storage 

vessels and 

centrifugal 

compressors

§60.9 Availability of 

information

Yes
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§60.10 State authority Yes 

§60.11 Compliance with 

standards and 

maintenance 

requirements

No Requirements are 

specified in 

subpart OOOO.

§60.12 Circumvention Yes

§60.13 Monitoring 

requirements

Yes Continuous monitors 

are required for 

storage vessels

§60.14 Modification Yes

§60.15 Reconstruction Yes

§60.16 Priority list Yes

§60.17 Incorporations by 

reference

Yes

§60.18 General control 

device requirements

Yes Except that §60.18 

does not apply to 

flares.

§60.19 General 

notification and 

reporting 

requirement

Yes