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Title 40 → Chapter I → Subchapter C → Part 60 → Subpart OOOO

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Title 40: Protection of Environment 

PART 60—STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

Subpart OOOO—Standards of Performance for Crude Oil and Natural 

Gas Production, Transmission and Distribution

Contents

§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 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]

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

SOURCE: 77 FR 49542, Aug. 16, 2012, unless otherwise noted. 

§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 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 gasdriven 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.

(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 paragraphs (e)(1) through 

(4) of this section. The potential for VOC emissions must be calculated using a generally accepted model 

or calculation methodology, based on the maximum average daily throughput determined for a 30-day 

period of production prior to the applicable emission determination deadline specified in this section. The 

determination may take into account requirements under a legally and practically enforceable limit in an 

operating permit or other requirement established under a Federal, State, local or tribal authority.

(1) For each new, modified or reconstructed storage vessel receiving liquids pursuant to the 

standards for gas well affected facilities in §60.5375, including wells subject to §60.5375(f), you must 

determine the potential for VOC emissions within 30 days after startup of production.

(2) A storage vessel affected facility that subsequently has its potential for VOC emissions decrease 

to less than 6 tpy shall remain an affected facility under this subpart.

(3) For storage vessels not subject to a legally and practically enforceable limit in an operating 

permit or other requirement established under Federal, state, local or tribal authority, any vapor from the 

storage vessel that is recovered and routed to a process through a VRU designed and operated as 

specified in this section is not required to be included in the determination of VOC potential to emit for 

purposes of determining affected facility status, provided you comply with the requirements in paragraphs 

(e)(3)(i) through (iv) of this section.

(i) You meet the cover requirements specified in §60.5411(b).

(ii) You meet the closed vent system requirements specified in §60.5411(c).

(iii) You maintain records that document compliance with paragraphs (e)(3)(i) and (ii) of this section.

(iv) In the event of removal of apparatus that recovers and routes vapor to a process, or operation

that is inconsistent with the conditions specified in paragraphs (e)(3)(i) and (ii) of this section, you must 

determine the storage vessel's potential for VOC emissions according to this section within 30 days of 

such removal or operation.

(4) For each new, reconstructed, or modified storage vessel with startup, startup of production, or 

which is returned to service, affected facility status is determined as follows: If a storage vessel is 

reconnected to the original source of liquids; used to replace any storage vessel affected facility; or is 

installed in parallel with any storage vessel affected facility, it is a storage vessel affected facility subject 

to the same requirements as before being removed from service, or applicable to the storage vessel 

affected facility being replaced, or with which it is installed in parallel immediately upon startup, startup of 

production, or return to service.

(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, 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 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.

(4) A gas well facility initially constructed after August 23, 2011, is considered an affected facility 

regardless of this provision.

[77 FR 49542, Aug. 16, 2012, as amended at 78 FR 58435, Sept. 23, 2013; 79 FR 79036, Dec. 31, 2014]

§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 requirements of paragraphs 

(a)(3) and (4) of this section unless a more stringent state or local emission control requirement is 

applicable; optionally, you may comply with the requirements of paragraphs (a)(1) through (4) of this 

section. For each new well completion operation with hydraulic fracturing begun on or after January 1, 

2015, you must comply with the requirements in paragraphs (a)(1) through (4) of this section. You must 

maintain a log as specified in paragraph (b).

(1) For each stage of the well completion operation, as defined in §60.5430, follow the requirements 

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

(i) During the initial flowback stage, route the flowback into one or more well completion vessels or 

storage vessels and commence operation of a separator unless it is technically infeasible for a separator 

to function. Any gas present in the initial flowback stage is not subject to control under this section.

(ii) During the separation flowback stage, route all recovered liquids from the separator to one or 

more well completion vessels or storage vessels, re-inject the liquids into the well or another well or route 

the recovered liquids to a collection system. Route the recovered gas from the separator into a gas flow 

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

as an on-site fuel source, or use the recovered gas for another useful purpose that a purchased fuel or 

raw material would serve. If it is infeasible to route the recovered gas as required above, follow the 

requirements in paragraph (a)(3) of this section. If, at any time during the separation flowback stage, it is 

not technically feasible for a separator to function, you must comply with (a)(1)(i) of this section.

(2) All salable quality recovered gas must be routed to the gas flow line as soon as practicable. In 

cases where salable quality gas cannot be directed to the flow line, you must follow the requirements in 

paragraph (a)(3) of this section.

(3) You must capture and direct recovered gas to a completion combustion device, except in 

conditions that may result in a fire hazard or explosion, or where high heat emissions from a completion 

combustion device may negatively impact tundra, permafrost or waterways. Completion combustion 

devices must be equipped with a reliable continuous ignition source.

(4) You have a general duty to safely maximize resource recovery and minimize releases to the 

atmosphere during flowback and subsequent recovery.

(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 

non-delineation low pressure gas well.

(2) Route the flowback into one or more well completion vessels and commence operation of a 

separator unless it is technically infeasible for a separator to function. Any gas present in the flowback 

before the separator can function is not subject to control under this section. You must capture and direct 

recovered gas to a completion combustion device, except in conditions that may result in a fire hazard or 

explosion, or where high heat emissions from a completion combustion device may negatively impact 

tundra, permafrost or waterways. Completion combustion devices must be equipped with a reliable 

continuous ignition source. You must also comply with paragraphs (a)(4) and (b) through (e) of this 

section.

(3) You must maintain records specified in §60.5420(c)(1)(iii) for wildcat, delineation and low 

pressure gas wells.

[77 FR 49542, Aug. 16, 2012, as amended at 79 FR 79037, Dec. 31, 2014]

§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.

(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.

[77 FR 49542, Aug. 16, 2012, as amended at 78 FR 58436, Sept. 23, 2013]

§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 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.

(d) You must perform the required notification, recordkeeping, and reporting as required by 

§60.5420.

[77 FR 49542, Aug. 16, 2012, as amended at 79 FR 79037, Dec. 31, 2014]

§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.

(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.

(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).

[77 FR 49542, Aug. 16, 2012, as amended at 78 FR 58436, Sept. 23, 2013; 79 FR 79038, Dec. 31, 2014]

§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.

(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) of this section. For storage vessel affected facilities receiving liquids 

pursuant to the standards for gas well affected facilities in §60.5375, you must achieve the required 

emissions reductions within 60 days after startup of production as defined in §60.5430.
(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.

(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. If you remove a Group 1 or Group 2 storage vessel affected facility from 

service, you must comply with paragraphs (f)(1) through (3) of this section. A Group 1 or Group 2 storage 

vessel is not an affected facility under this subpart for the period that it is removed from service.

(1) For a storage vessel affected facility to be removed from service, you must comply with the 

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

(i) You must completely empty and degas the storage vessel, such that the storage vessel no longer 

contains crude oil, condensate, produced water or intermediate hydrocarbon liquids. A storage vessel 

where liquid is left on walls, as bottom clingage or in pools due to floor irregularity is considered to be 

completely empty.

(ii) You must submit a notification as required in §60.5420(b)(6)(vi) in your next annual report, 

identifying each storage vessel affected facility removed from service during the reporting period and the 

date of its removal from service.

(2) If a storage vessel identified in paragraph (f)(1)(ii) of this section is returned to service, you must 

determine its affected facility status as provided in §60.5365(e).
(3) For each storage vessel affected facility returned to service during the reporting period, you must 

submit a notification in your next annual report as required in §60.5420(b)(6)(vii), identifying each storage 

vessel affected facility and the date of its return to service.

(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.

[78 FR 58436, Sept. 23, 2013, as amended at 79 FR 79038, Dec. 31, 2014]

§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.

(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 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.

(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.

(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 150 

°C (302 °F) 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 

150 °C (302 °F) 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, 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 re-monitored.

[77 FR 49542, Aug. 16, 2012, as amended at 79 FR 79038, Dec. 31, 2014]

§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 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 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).
(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 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:

(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.

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 cross-sectional 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 reduction-type devices or where the oxygen content of the effluent gas is less than 1.0 

percent by volume. The sampling rate must be at 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, 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 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).

(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 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 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.

(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 interval. 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 sulfur emission 

reduction efficiency achieved for each 24-hour period by:

View or download PDF

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?

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.

(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 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 starch-iodine end point is much less distinct, and a blank determination of end point, 

with H2S-free gas or air, is required.
§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).

(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 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).

(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.

(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 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.

(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).

(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).

[77 FR 49542, Aug. 16, 2012, as amended at 78 FR 58437, Sept. 23, 2013; 79 FR 79038, Dec. 31, 2014]

§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 

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.
(B) You must secure the bypass device valve installed at the inlet to the bypass device in the nondiverting 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 impermeable 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;

(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.

(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 nondiverting 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.

[77 FR 49542, Aug. 16, 2012, as amended at 78 FR 58438, Sept. 23, 2013; 79 FR 79038, Dec. 31, 2014]

§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.

(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 nondestructive 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.

(b) You must operate each control device installed on your centrifugal compressor affected facility in 

accordance with the requirements specified in paragraphs (b)(1) and (2) of this section.

(1) You must operate each control device used to comply with this subpart at all times when gases, 

vapors, and fumes are vented from the wet seal fluid degassing system affected facility, as required 

under §60.5380(a), through the closed vent system to the control device. You may vent more than one 

affected facility to a control device used to comply with this subpart.
(2) For each control device monitored in accordance with the requirements of §60.5417(a) through 

(g), you must demonstrate compliance according to the requirements of §60.5415(b)(2), as applicable.

(c) For each carbon adsorption system used as a control device to meet the requirements of 

paragraph (a)(2) or (d)(2) of this section, you must manage the carbon in accordance with the 

requirements specified in paragraphs (c)(1) or (2) of this section.

(1) Following the initial startup of the control device, you must replace all carbon in the control 

device with fresh carbon on a regular, predetermined time interval that is no longer than the carbon 

service life established according to §60.5413(c)(2) or (3) or according to the design 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 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 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 nondestructive control device must be designed and operated to reduce the mass content of VOC in the 

gases vented to the device by 95.0 percent by weight or greater. A carbon replacement schedule must be 

included in the design of the carbon adsorption system.

(3) You must operate each control device used to comply with this subpart at all times when gases, 

vapors, and fumes are vented from the storage vessel affected facility through the closed vent system to 

the control device. You may vent more than one affected facility to a control device used to comply with 

this subpart.

[77 FR 49542, Aug. 16, 2012, as amended at 78 FR 58438, Sept. 23, 2013; 79 FR 79039, Dec. 31, 2014]

§60.5413 What are the performance testing procedures for control devices used to demonstrate 

compliance at my storage vessel or centrifugal compressor affected facility?

This section applies to the performance testing of control devices used to demonstrate compliance 

with the emissions standards for your centrifugal compressor affected facility. You must demonstrate that 

a control device achieves the performance requirements of §60.5412(a) using the performance test 

methods and procedures specified in this section. For condensers, you may use a design analysis as 

specified in paragraph (c) of this section in lieu of complying with paragraph (b) of this section. In addition, 

this section contains the requirements for enclosed combustion device performance tests conducted by 

the manufacturer applicable to both storage vessel and centrifugal compressor affected facilities.

(a) 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 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 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:

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.

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:

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 weightpercent 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 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.

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:

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.

%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.

(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 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 that a specific model of control device achieves the 

performance requirements in paragraph (d)(11) of this section by conducting a performance test as 

specified in paragraphs (d)(2) through (10) of this section. You must submit a test report for each 

combustion control device in accordance with the requirements in paragraph (d)(12) of this section.

(2) Performance testing must consist of three one-hour (or longer) test runs for each of the four firing 

rate settings specified in paragraphs (d)(2)(i) through (iv) of this section, making a total of 12 test runs per 

test. Propene (propylene) gas must be used for the testing fuel. All fuel analyses must be performed by 

an independent third-party laboratory (not affiliated with the control device manufacturer or fuel supplier).

(i) 90-100 percent of maximum design rate (fixed rate).

(ii) 70-100-70 percent (ramp up, ramp down). Begin the test at 70 percent of the maximum design 

rate. During the first 5 minutes, incrementally ramp the firing rate to 100 percent of the maximum design 

rate. Hold at 100 percent for 5 minutes. In the 10-15 minute time range, incrementally ramp back down to 

70 percent of the maximum design rate. Repeat three more times for a total of 60 minutes of sampling.

(iii) 30-70-30 percent (ramp up, ramp down). Begin the test at 30 percent of the maximum design 

rate. During the first 5 minutes, incrementally ramp the firing rate to 70 percent of the maximum design 

rate. Hold at 70 percent for 5 minutes. In the 10-15 minute time range, incrementally ramp back down to 

30 percent of the maximum design rate. Repeat three more times for a total of 60 minutes of sampling.

(iv) 0-30-0 percent (ramp up, ramp down). Begin the test at the minimum firing rate. During the first 

5 minutes, incrementally ramp the firing rate to 30 percent of the maximum design rate. Hold at 30 

percent for 5 minutes. In the 10-15 minute time range, incrementally ramp back down to the minimum 

firing rate. Repeat three more times for a total of 60 minutes of sampling.

(3) All models employing multiple enclosures must be tested simultaneously and with all burners 

operational. Results must be reported for each enclosure individually and for the average of the 

emissions from all interconnected combustion enclosures/chambers. Control device operating data must 

be collected continuously throughout the performance test using an electronic Data Acquisition System. A 
graphic presentation or strip chart of the control device operating data and emissions test data must be 

included in the test report in accordance with paragraph (d)(12) of this section. Inlet fuel meter data may 

be manually recorded provided that all inlet fuel data readings are included in the final report.

(4) Inlet testing must be conducted as specified in paragraphs (d)(4)(i) through (ii) of this section.

(i) The inlet gas flow metering system must be located in accordance with Method 2A, 40 CFR part 

60, appendix A-1, (or other approved procedure) to measure inlet gas flow rate at the control device inlet 

location. You must position the fitting for filling fuel sample containers a minimum of eight pipe diameters 

upstream of any inlet gas flow monitoring meter.

(ii) Inlet flow rate must be determined using Method 2A, 40 CFR part 60, appendix A-1. Record the 

start and stop reading for each 60-minute THC test. Record the gas pressure and temperature at 5-

minute intervals throughout each 60-minute test.

(5) Inlet gas sampling must be conducted as specified in paragraphs (d)(5)(i) through (ii) of this 

section.

(i) At the inlet gas sampling location, securely connect a Silonite-coated stainless steel evacuated 

canister fitted with a flow controller sufficient to fill the canister over a 3-hour period. Filling must be 

conducted as specified in paragraphs (d)(5)(i)(A) through (C) of this section.

(A) Open the canister sampling valve at the beginning of each test run, and close the canister at the 

end of each test run.

(B) Fill one canister across the three test runs such that one composite fuel sample exists for each 

test condition.

(C) Label the canisters individually and record sample information on a chain of custody form.

(ii) Analyze each inlet gas sample using the methods in paragraphs (d)(5)(ii)(A) through (C) of this 

section. You must include the results in the test report required by paragraph (d)(12) of this section.

(A) Hydrocarbon compounds containing between one and five atoms of carbon plus benzene using 

ASTM D1945-03.

(B) Hydrogen (H2), carbon monoxide (CO), carbon dioxide (CO2), nitrogen (N2), oxygen (O2) using 

ASTM D1945-03.

(C) Higher heating value using ASTM D3588-98 or ASTM D4891-89.

(6) Outlet testing must be conducted in accordance with the criteria in paragraphs (d)(6)(i) through 

(v) of this section.

(i) Sample and flow rate must be measured in accordance with paragraphs (d)(6)(i)(A) through (B) of 

this section.

(A) The outlet sampling location must be a minimum of four equivalent stack diameters downstream 

from the highest peak flame or any other flow disturbance, and a minimum of one equivalent stack 

diameter upstream of the exit or any other flow disturbance. A minimum of two sample ports must be 

used.
(B) Flow rate must be measured using Method 1, 40 CFR part 60, appendix A-1 for determining flow 

measurement traverse point location, and Method 2, 40 CFR part 60, appendix A-1 for measuring duct 

velocity. If low flow conditions are encountered (i.e., velocity pressure differentials less than 0.05 inches 

of water) during the performance test, a more sensitive manometer must be used to obtain an accurate 

flow profile.

(ii) Molecular weight and excess air must be determined as specified in paragraph (d)(7) of this 

section.

(iii) Carbon monoxide must be determined as specified in paragraph (d)(8) of this section.

(iv) THC must be determined as specified in paragraph (d)(9) of this section.

(v) Visible emissions must be determined as specified in paragraph (d)(10) of this section.

(7) Molecular weight and excess air determination must be performed as specified in paragraphs 

(d)(7)(i) through (iii) of this section.

(i) An integrated bag sample must be collected during the Method 4, 40 CFR part 60, appendix A-3, 

moisture test following the procedure specified in (d)(7)(i)(A) through (B) of this section. Analyze the bag 

sample using a gas chromatograph-thermal conductivity detector (GC-TCD) analysis meeting the criteria 

in paragraphs (d)(7)(i)(C) through (D) of this section.

(A) Collect the integrated sample throughout the entire test, and collect representative volumes from 

each traverse location.

(B) Purge the sampling line with stack gas before opening the valve and beginning to fill the bag. 

Clearly label each bag and record sample information on a chain of custody form.

(C) The bag contents must be vigorously mixed prior to the gas chromatograph analysis.

(D) The GC-TCD calibration procedure in Method 3C, 40 CFR part 60, appendix A, must be 

modified by using EPA Alt-045 as follows: For the initial calibration, triplicate injections of any single 

concentration must agree within 5 percent of their mean to be valid. The calibration response factor for a 

single concentration re-check must be within 10 percent of the original calibration response factor for that 

concentration. If this criterion is not met, repeat the initial calibration using at least three concentration 

levels.

(ii) Calculate and report the molecular weight of oxygen, carbon dioxide, methane, and nitrogen in 

the integrated bag sample and include in the test report specified in paragraph (d)(12) of this section. 

Moisture must be determined using Method 4, 40 CFR part 60, appendix A-3. Traverse both ports with 

the Method 4, 40 CFR part 60, appendix A-3, sampling train during each test run. Ambient air must not be 

introduced into the Method 3C, 40 CFR part 60, appendix A-2, integrated bag sample during the port 

change.

(iii) Excess air must be determined using resultant data from the EPA Method 3C tests and EPA 

Method 3B, 40 CFR part 60, appendix A, equation 3B-1.

(8) Carbon monoxide must be determined using Method 10, 40 CFR part 60, appendix A. Run the 

test simultaneously with Method 25A, 40 CFR part 60, appendix A-7 using the same sampling points. An 

instrument range of 0-10 parts per million by volume-dry (ppmvd) is recommended.
(9) Total hydrocarbon determination must be performed as specified by in paragraphs (d)(9)(i) 

through (vii) of this section.

(i) Conduct THC sampling using Method 25A, 40 CFR part 60, appendix A-7, except that the option 

for locating the probe in the center 10 percent of the stack is not allowed. The THC probe must be 

traversed to 16.7 percent, 50 percent, and 83.3 percent of the stack diameter during each test run.

(ii) A valid test must consist of three Method 25A, 40 CFR part 60, appendix A-7, tests, each no less 

than 60 minutes in duration.

(iii) A 0-10 parts per million by volume-wet (ppmvw) (as propane) measurement range is preferred; 

as an alternative a 0-30 ppmvw (as carbon) measurement range may be used.

(iv) Calibration gases must be propane in air and be certified through EPA Protocol 1—“EPA 

Traceability Protocol for Assay and Certification of Gaseous Calibration Standards,” September 1997, as 

amended August 25, 1999, EPA-600/R-97/121(or more recent if updated since 1999).

(v) THC measurements must be reported in terms of ppmvw as propane.

(vi) THC results must be corrected to 3 percent CO2, as measured by Method 3C, 40 CFR part 60, 

appendix A-2. You must use the following equation for this diluent concentration correction:

Where:

Cmeas = The measured concentration of the pollutant.

CO2meas = The measured concentration of the CO2 diluent.

3 = The corrected reference concentration of CO2 diluent.

Ccorr = The corrected concentration of the pollutant.

(vii) Subtraction of methane or ethane from the THC data is not allowed in determining results.

(10) Visible emissions must be determined using Method 22, 40 CFR part 60, appendix A. The test 

must be performed continuously during each test run. A digital color photograph of the exhaust point, 

taken from the position of the observer and annotated with date and time, must be taken once per test run 

and the 12 photos included in the test report specified in paragraph (d)(12) of this section.

(11) Performance test criteria. (i) The control device model tested must meet the criteria in 

paragraphs (d)(11)(i)(A) through (D) of this section. These criteria must be reported in the test report 

required by paragraph (d)(12) of this section.

(A) Method 22, 40 CFR part 60, appendix A, results under paragraph (d)(10) of this section with no 

indication of visible emissions.

(B) Average Method 25A, 40 CFR part 60, appendix A, results under paragraph (d)(9) of this section 

equal to or less than 10.0 ppmvw THC as propane corrected to 3.0 percent CO2.

(C) Average CO emissions determined under paragraph (d)(8) of this section equal to or less than 

10 parts ppmvd, corrected to 3.0 percent CO2.
(D) Excess combustion air determined under paragraph (d)(7) of this section equal to or greater 

than 150 percent.

(ii) The manufacturer must determine a maximum inlet gas flow rate which must not be exceeded for 

each control device model to achieve the criteria in paragraph (d)(11)(iii) of this section. The maximum 

inlet gas flow rate must be included in the test report required by paragraph (d)(12) of this section.

(iii) A control device meeting the criteria in paragraph (d)(11)(i)(A) through (D) of this section must 

demonstrate a destruction efficiency of 95 percent for VOC regulated under this subpart.

(12) The owner or operator of a combustion control device model tested under this 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.

(A) Fuel gas delivery pressure and temperature.

(B) Fuel gas moisture range.

(C) Purge gas usage range.

(D) Condensate (liquid fuel) separation range.

(E) Combustion zone temperature range. This is required for all devices that measure this 

parameter.

(F) Excess combustion air range.

(G) Flame arrestor(s).

(H) Burner manifold.

(I) Pilot flame indicator.

(J) Pilot flame design fuel and calculated or measured fuel usage.

(K) Tip velocity range.

(L) Momentum flux ratio.
(M) Exit temperature range.

(N) Exit flow rate.

(O) Wind velocity and direction.

(vi) The test report must include all calibration quality assurance/quality control data, calibration gas 

values, gas cylinder certification, strip charts, or other graphic presentations of the data annotated with 

test times and calibration values.

(e) Continuous compliance for combustion control devices tested by the manufacturer in accordance 

with paragraph (d) of this section. This paragraph applies to the demonstration of compliance for a 

combustion control device tested under the provisions in paragraph (d) of this section. Owners or 

operators must demonstrate that a control device achieves the performance requirements in (d)(11) of 

this section by installing a device tested under paragraph (d) of this section and complying with the 

criteria specified in paragraphs (e)(1) through (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 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 Web site: epa.gov/airquality/oilandgas/.

(7) Ensure that each enclosed combustion device is maintained in a leak free condition.

[77 FR 49542, Aug. 16, 2012, as amended at 78 FR 58439, Sept. 23, 2013; 79 FR 79039, Dec. 31, 2014]

§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?

(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.

(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 required zero and span adjustments). A 

monitoring system malfunction is any sudden, infrequent, not reasonably preventable failure of the 

monitoring system to provide valid data. Monitoring system failures that are caused in part by poor 

maintenance or careless operation are not malfunctions. You are required to complete monitoring system 

repairs in response to monitoring system malfunctions and to return the monitoring system to operation 

as expeditiously as practicable.

(v) You may not use data recorded during monitoring system malfunctions, repairs associated with 

monitoring system malfunctions, or required monitoring system quality assurance or control activities in 

calculations used to report emissions or operating levels. You must use all the data collected during all 

other required data collection periods to assess the operation of the control device and associated control 

system.

(vi) Failure to collect required data is a deviation of the monitoring requirements, except for periods 

of monitoring system malfunctions, repairs associated with monitoring system malfunctions, and required 

quality monitoring system quality assurance or quality control activities (including, as applicable, system 

accuracy audits and required zero and span adjustments).

(vii) If you use a combustion control device to meet the requirements of §60.5412(a) and you 

demonstrate compliance using the test procedures specified in §60.5413(b), you must comply with 

paragraphs (b)(2)(vii)(A) through (D) of this section.

(A) A pilot flame must be present at all times of operation.
(B) Devices must be operated with no visible emissions, except for periods not to exceed a total of 2 

minutes during any hour. A visible emissions test using 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 60, appendix A, visual observation as described in paragraph (b)(2)(vii)(B) of this 

section.

(viii) If you use a condenser as the control device to achieve the percent reduction performance 

requirements specified in §60.5412(a)(2), you must demonstrate compliance using the procedures in 

paragraphs (b)(2)(viii)(A) through (E) of this section.

(A) You must establish a site-specific condenser performance curve according to §60.5417(f)(2).

(B) You must calculate the daily average condenser outlet temperature in accordance with 

§60.5417(e).

(C) You must determine the condenser efficiency for the current operating day using the daily 

average condenser outlet temperature calculated under paragraph (b)(2)(viii)(B) of this section and the 

condenser performance curve established under paragraph (b)(2)(viii)(A) of this section.

(D) Except as provided in paragraphs (b)(2)(viii)(D)(1) and (2) of this section, at the end of each 

operating day, you must calculate the 365-day rolling average TOC emission reduction, as appropriate, 

from the condenser efficiencies as determined in paragraph (b)(2)(viii)(C) of this section.

(1) After the compliance dates specified in §60.5370, if you have less than 120 days of data for 

determining average TOC emission reduction, you must calculate the average TOC emission reduction 

for the first 120 days of operation after the compliance dates. You have demonstrated compliance with 

the overall 95.0 percent reduction requirement if the 120-day average TOC emission reduction is equal to 

or greater than 95.0 percent.

(2) After 120 days and no more than 364 days of operation after the compliance date specified in 

§60.5370, you must calculate the average TOC emission reduction as the TOC emission reduction 

averaged over the number of days between the current day and the applicable compliance date. You 

have demonstrated compliance with the overall 95.0 percent reduction requirement, if the average TOC 

emission reduction is equal to or greater than 95.0 percent.

(E) If you have data for 365 days or more of operation, you have demonstrated compliance with the 

TOC emission reduction if the rolling 365-day average TOC emission reduction calculated in paragraph 

(b)(2)(viii)(D) of this section is equal to or greater than 95.0 percent.

(3) You must submit the annual report required by 60.5420(b) and maintain the records as specified 

in §60.5420(c)(2).

(c) For each reciprocating compressor affected facility complying with §60.5385(a)(1) or (2), you 

must demonstrate continuous compliance according to paragraphs (c)(1) through (3) of this section. For 
each reciprocating compressor affected facility complying with §60.5385(a)(3), you must demonstrate 

continuous compliance according to paragraph (c)(4) of this section.

(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).

(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)-(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 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.

(2) The emission reduction efficiency (R) achieved by the sulfur reduction technology must be 

determined using the procedures in §60.5406(c)(1).

[77 FR 49542, Aug. 16, 2012, as amended at 78 FR 58442, Sept. 23, 2013; 79 FR 79039, Dec. 31, 2014]

§60.5416 What are the initial and continuous cover and closed vent system inspection and 

monitoring requirements for my storage vessel, centrifugal compressor and reciprocating 

compressor affected facilities?

For each closed vent system or cover at your storage vessel, centrifugal compressor and 

reciprocating compressor affected facility, you must comply with the applicable requirements of 

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

(a) Inspections for closed vent systems and covers installed on each centrifugal compressor or 

reciprocating compressor affected facility. Except as provided in paragraphs (b)(11) and (12) of this 

section, you must inspect each closed vent system according to the procedures and schedule specified in 

paragraphs (a)(1) and (2) of this section, inspect each cover according to the procedures and schedule 

specified in paragraph (a)(3) of this section, and inspect each bypass device according to the procedures 

of paragraph (a)(4) of this section.

(1) For each closed vent system joint, seam, or other connection that is permanently or semipermanently sealed (e.g., 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.

(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 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 nondiverting position using a car-seal or a lock-and-key type configuration, visually inspect the seal or closure 

mechanism at least once every month to verify that the valve is maintained in the non-diverting position 

and the vent stream is not diverted through the bypass device. You must maintain records of the 

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

(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.

(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 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 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.
(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-to-inspect 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.

(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; loose connections; liquid 

leaks; or broken or missing caps or other closure devices.

(iii) Monthly inspections must be separated by at least 14 calendar days.

(2) For each cover, you must conduct inspections at least once every calendar month as specified in 

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

(i) You must maintain records of the inspection results as specified in §60.5420(c)(7).

(ii) Conduct olfactory, visual and auditory inspections for defects that could result in air emissions. 

Defects include, but are not limited to, visible cracks, holes, or gaps in the cover, or between the cover 

and the separator wall; broken, cracked, or otherwise damaged seals or gaskets on closure devices; and 

broken or missing hatches, access covers, caps, or other closure devices. In the case where the storage 

vessel is buried partially or entirely underground, you must inspect only those portions of the cover that 
extend to or above the ground surface, and those connections that are on such portions of the cover 

(e.g., fill ports, access hatches, gauge wells, etc.) and can be opened to the atmosphere.

(iii) Monthly inspections must be separated by at least 14 calendar days.

(3) For each bypass device, except as provided for in §60.5411(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 nondiverting 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.

(i) A first attempt at repair must be made no later than 5 calendar days after the leak is detected.

(ii) Repair must be completed no later than 30 calendar days after the leak is detected.

(iii) Grease or another applicable substance must be applied to deteriorating or cracked gaskets to 

improve the seal while awaiting repair.

(5) Delay of repair. Delay of repair of a closed vent system or cover for which leaks or defects have 

been detected is allowed if the repair is technically infeasible without a shutdown, or if you determine that 

emissions resulting from immediate repair would be greater than the fugitive emissions likely to result 

from delay of repair. You must complete repair of such equipment by the end of the next shutdown.

(6) Unsafe to inspect requirements. You may designate any parts of the closed vent system or cover 

as unsafe to inspect if the requirements in paragraphs (c)(6)(i) and (ii) of this section are met. Unsafe to 

inspect parts are exempt from the inspection requirements of paragraphs (c)(1) and (2) of this section.

(i) You determine that the equipment is unsafe to inspect because inspecting personnel would be 

exposed to an imminent or potential danger as a consequence of complying with paragraphs (c)(1) or (2) 

of this section.

(ii) You have a written plan that requires inspection of the equipment as frequently as practicable 

during safe-to-inspect 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.

[77 FR 49542, Aug. 16, 2012, as amended at 78 FR 58443, Sept. 23, 2013; 79 FR 79039, Dec. 31, 2014]

§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 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.

(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.

(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 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, 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 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 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 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.

(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 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 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.

(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 (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.

(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).

[77 FR 49542, Aug. 16, 2012, as amended at 78 FR 58443, Sept. 23, 2013]

§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 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 

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.

(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.

(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 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.

(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 

http://www.epa.gov/ttn/chief/ert/index.html) existing at the time of the performance test to generate a 

submission package file, which documents the performance test. You must then submit the file generated 

by the ERT through the EPA's Compliance and Emissions Data Reporting Interface (CEDRI), which can 

be accessed by logging in to the EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/). Only data 

collected using test methods supported by the ERT as listed on the ERT Web site are subject to this 

requirement for submitting reports electronically. Owners or operators who claim that some of the 

information being submitted for performance tests is confidential business information (CBI) must submit 

a complete ERT file including information claimed to be CBI on a compact disk or other commonly used 

electronic storage media (including, but not limited to, flash drives) to EPA. The electronic media must be 

clearly marked as CBI and mailed to U.S. EPA/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 

conducted using test methods that are not listed on the ERT Web site, the owner or operator shall submit 

the results of the performance test to the Administrator at the appropriate address listed in §60.4.

(ii) All reports, except as specified in paragraph (b)(8) of this section, required by this subpart not 

subject to the requirements in paragraph (a)(2)(i) of this section must be sent to the Administrator at the 

appropriate address listed in §60.4 of this part. The Administrator or the delegated authority may request 

a report in any form suitable for the specific case (e.g., by commonly used electronic media such as Excel 

spreadsheet, on CD or hard copy).
(8) For enclosed combustors tested by the manufacturer in accordance with §60.5413(d), an 

electronic copy of the performance test results required by §60.5413(d) shall be submitted via email to 

Oil_and_Gas_PT@EPA.GOV unless the test results for that model of combustion control device are 

posted at the following Web site: epa.gov/airquality/oilandgas/.

(c) Recordkeeping requirements. You must maintain the records identified as specified in §60.7(f) 

and in paragraphs (c)(1) through (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.

(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 of each attempt to direct flowback to a 

separator as required in §60.5375(a)(1)(i); the date and time of each occurrence of returning to the initial 

flowback stage under §60.5375(a)(1)(i); and the date and time that the well was shut in and the flowback 

equipment was permanently disconnected, or the startup of production; the duration of flowback; duration 

of recovery to the flow line; duration of combustion; duration of venting; and specific reasons for venting in 

lieu of capture or combustion. The duration must be specified in hours of time.

(B) For each gas well affected facility required to comply with the requirements of §60.5375(f), you 

must maintain the records specified in paragraph (c)(1)(iii)(A) of this section except that you do not have 

to record the duration of recovery to the flow line.

(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.

(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 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 (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) 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 §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 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.

[77 FR 49542, Aug. 16, 2012, as amended at 78 FR 58445, Sept. 23, 2013; 79 FR 79039, Dec. 31, 2014]

§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.

(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.

§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).

Back to Top

§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.

(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?

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 square-mile 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:

(1) For a corporation: A president, secretary, treasurer, or vice-president of the corporation in charge 

of a principal business function, or any other person who performs similar policy or decision-making 

functions for the corporation, or a duly authorized representative of such person if the representative is 

responsible for the overall operation of one or more manufacturing, production, or operating facilities 

applying for or subject to a permit and either:

(i) The facilities employ more than 250 persons or have gross annual sales or expenditures 

exceeding $25 million (in second quarter 1980 dollars); or

(ii) The Administrator is notified of such delegation of authority prior to the exercise of that authority. 

The Administrator reserves the right to evaluate such delegation;

(2) For a partnership (including but not limited to general partnerships, limited partnerships, and 

limited liability partnerships) or sole proprietorship: A general partner or the proprietor, respectively. If a 

general partner is a corporation, the provisions of paragraph (1) of this definition apply;

(3) For a municipality, State, Federal, or other public agency: Either a principal executive officer or 

ranking elected official. For the purposes of this part, a principal executive officer of a Federal agency 

includes the chief executive officer having responsibility for the overall operations of a principal 

geographic unit of the agency (e.g., a Regional Administrator of EPA); or

(4) For affected facilities:

(i) The designated representative in so far as actions, standards, requirements, or prohibitions under 

title IV of the Clean Air Act or the regulations promulgated thereunder are concerned; or

(ii) The designated representative for any other purposes under part 60.

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.

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:

(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.

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 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.

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.

Initial flowback stage means the period during a well completion operation which begins at the onset 

of flowback and ends at the separation flowback stage.

Intermediate hydrocarbon liquid means any naturally occurring, unrefined petroleum liquid.

Intermittent/snap-action pneumatic controller means a pneumatic controller that vents noncontinuously.

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.

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).

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.

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 emissions completion means a well completion following fracturing or refracturing where 

gas flowback that is otherwise vented is captured, cleaned, and routed to the flow line or collection 

system, re-injected into the well or another well, used as an on-site fuel source, or used for other useful 

purpose that a purchased fuel or raw material would serve, with no direct release to the atmosphere.

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 process for a purpose other than maintenance in accordance with §60.5395(f)(1).

Responsible official means one of the following:

(1) For a corporation: A president, secretary, treasurer, or vice-president of the corporation in charge 

of a principal business function, or any other person who performs similar policy or decision-making 

functions for the corporation, or a duly authorized representative of such person if the representative is 

responsible for the overall operation of one or more manufacturing, production, or operating facilities 

applying for or subject to a permit and either:

(i) The facilities employ more than 250 persons or have gross annual sales or expenditures 

exceeding $25 million (in second quarter 1980 dollars); or

(ii) The delegation of authority to such representatives is approved in advance by the permitting 

authority;

(2) For a partnership or sole proprietorship: A general partner or the proprietor, respectively;

(3) For a municipality, State, Federal, or other public agency: Either a principal executive officer or 

ranking elected official. For the purposes of this part, a principal executive officer of a Federal agency 

includes the chief executive officer having responsibility for the overall operations of a principal 

geographic unit of the agency (e.g., a Regional Administrator of EPA); or

(4) For affected facilities:

(i) The designated representative in so far as actions, standards, requirements, or prohibitions under 

title IV of the Clean Air Act or the regulations promulgated thereunder are concerned; or

(ii) The designated representative for any other purposes under part 60.

Returned to service means that a Group 1 or Group 2 storage vessel affected facility that was 

removed from service has been:

(1) Reconnected to the original source of liquids, connected in parallel to any storage vessel 

affected facility or has been used to replace any storage vessel affected facility; or

(2) Installed in any location covered by this subpart and introduced with crude oil, condensate, 

intermediate hydrocarbon liquids or produced water.

Routed to a process or route to a process means the emissions are conveyed via a closed vent 

system to any enclosed portion of a process where the emissions are predominantly recycled and/or 

consumed in the same manner as a material that fulfills the same function in the process and/or 

transformed by chemical reaction into materials that are not regulated materials and/or incorporated into a 

product; and/or recovered.

Salable quality gas means natural gas that meets the flow line or collection system operator 

specifications, regardless of whether such gas is sold.

Separation flowback stage means the period during a well completion operation when it is 

technically feasible for a separator to function. The separation flowback stage ends either at the startup of 

production, or when the well is shut in and permanently disconnected from the flowback equipment.
Startup of production means the beginning of initial flow following the end of flowback when there is 

continuous recovery of salable quality gas and separation and recovery of any crude oil, condensate or 

produced water.

Storage vessel means a tank or other vessel that contains an accumulation of crude oil, 

condensate, intermediate hydrocarbon liquids, or produced water, and that is constructed primarily of 

nonearthen materials (such as wood, concrete, steel, fiberglass, or plastic) which provide structural 

support. Two or more storage vessels connected in parallel are considered equivalent to a single storage 

vessel with throughput equal to the total throughput of the storage vessels connected in parallel. A well 

completion vessel that receives recovered liquids from a well after startup of production following 

flowback for a period which exceeds 60 days is considered a storage vessel under this subpart. A tank or 

other vessel shall not be considered a storage vessel if it has been removed from service in accordance 

with the requirements of §60.5395(f) until such time as such tank or other vessel has been returned to 

service. For the purposes of this subpart, the following are not considered storage vessels:

(1) Vessels that are skid-mounted or permanently attached to something that is mobile (such as 

trucks, railcars, barges or ships), and are intended to be located at a site for less than 180 consecutive 

days. If you do not keep or are not able to produce records, as required by §60.5420(c)(5)(iv), showing 

that the vessel has been located at a site for less than 180 consecutive days, the vessel described herein 

is considered to be a storage vessel from the date the original vessel was first located at the site. This 

exclusion does not apply to a well completion vessel as described above.

(2) Process vessels such as surge control vessels, bottoms receivers or knockout vessels.

(3) Pressure vessels designed to operate in excess of 204.9 kilopascals and without emissions to 

the atmosphere.

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.

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.
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.

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.

[77 FR 49542, Aug. 16, 2012, as amended at 78 FR 58447, Sept. 23, 2013; 79 FR 79040, Dec. 31, 2014]

§§60.5431-60.5499 [Reserved]

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≤300.0X>300.0

Y≥50 79.0 88.51X0.0101Y

0.0125 or 99.9, whichever is smaller.

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

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

smaller

93.5 93.5

Y<10 79.0 79.0 79.0 79.0

[78 FR 58447, Sept. 23, 2013]

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≤300.0X>300.0

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

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

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

smaller

90.8 90.8

Y<10 74.0 74.0 74.0 74.0
X = The sulfur feed rate from the sweetening unit (i.e., the H2S in the acid gas), expressed as sulfur, 

Mg/D(LT/D), rounded to one decimal place.

Y = The sulfur content of the acid gas from the sweetening unit, expressed as mole percent H2S (dry 

basis) rounded to one decimal place.

Z = The minimum required sulfur dioxide (SO2) emission reduction efficiency, expressed as percent 

carried to one decimal place. Zi refers to the reduction efficiency required at the initial performance test. Zc

refers to the reduction efficiency required on a continuous basis after compliance with Zi has been 

demonstrated.

[78 FR 58447, Sept. 23, 2013]

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.

§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.