Page 1 of 160

REDLINE/STRIKEOUT OF CHANGES

- OIL AND NATURAL GAS SECTOR: RECONSIDERATION OF CERTAIN PROVISIONS OF NEW SOURCE PERFORMANCE STANDARDS; PROPOSED RULE Subpart OOOO

— Standards of Performance for Crude Oil and Natur al Gas Production, Transmission and Distributi on for which Construction, Modification or Reconstruction Commenced after August 23, 2011 , and on or before September 18, 2015
Sec. 60.5360 What is the purpose of this subpart? 60.5365 Am I subject to this subpart? 60.5370 When must I comply with this su bpart? 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 p neumatic 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 t he 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 u nits 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 opera tions from my sweetening unit affected facilities at onshore natural gas processing plants? 60.5408 What is an o ptional procedure for measuring hydrogen

sulfide in acid gas

— Tutwiler Procedure? 60.5410 How do I demonstrate initial compliance with the

standa rds 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 andPage 2 of 160
sweetening unit af fected 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 emissions from storage vessels or centrifugal compressor wet seal flu id 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 th e 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, m y 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? 60.54 16 What are the initial and continuous cover and closed

vent system inspection and monitoring requirements for my storage vessel or centrifugal compressor affected facility? 60.5417 What are the continuous control device monitoring

requirements for my stor age 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 m y sweetening unit affected facilities at onshore natural gas processing plants? 60.5425 What part s 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 P art 60

– Requ ired Minimum Initial SO 2 Emission Reduction Efficiency (Z i )Page 3 of 160

Table 2 to Subpart OOOO of P art 60

– Required Minimum SO 2 Emission Reduction Efficiency (Z c ) Table 3 to Subpart OOOO of P art 60

– Applicability of General Provisions to Subpart OOOOPage 4 of 160

Subpart OOOO

— Standards of Performance for Crude Oil and Natur al Gas Production, Transmission and Distribution §60.5360 What is the purpose of this subpart? This subpart establishes emission standards and compliance schedules for the control of volatile organic compo unds (VOC) and sulfur dioxide (SO 2 ) emissions from affected facilities that commence construction, modification or reconstruction after August 23, 2011 , and on or before September 18, 2015

. §60.5365 Am I subject to this subpart? You are subject to the app licable 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 , and on or before September 18, 2015

. (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 well head 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.Page 5 of 160

(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 si te, or an adjacent well site and servicing more than one well site, is not an affected facility under this subpart. (d)(1) For the oil production segment (between the wellhead and the point of custody transfer to an oil pipeline), each pneumatic controller affected facility, which is a single continuous bleed natural gas

- driven pneumatic controller operating at a natural gas bleed rate greater than 6 scfh. (2) For the natural gas production segment (between the wellhead and the point of custody transfer to the natural gas transmission and storage segment and not including natural gas processing plants), each pneumatic controller affected facility, which is a single continuous bleed natural gas

- driven pneumatic controller operating at a natural gas bleed rate greater than 6 scfh. (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 vesse l located in the oil and natural gasPage 6 of 160

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 Octob er 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 calculate d 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 m ay 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 receiv ing 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 facilit y that subsequently has its potential for VOC emissions decrease to less than 6 tpy shall remain an affected facility under this subpart.Page 7 of 160

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

req uirement 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 determi nation 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 mee t 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, o r 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 toPage 8 of 160

service, affected facility status is determined as follows: If a storage vessel is reconnected to the original source of liquids or is used to replace 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, 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 ga s 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.Page 9 of 160

(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 t hey 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 t hat 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 hydrog en sulfide (H 2 S) 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 subpa rt. (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.Page 10 of 160

(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 re quirements 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 followin g 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, stora ge vessels, compressors, or pneumatic controllers located at the well site. (4) A gas well facility initially constructed after August 23, 2011, and on or before September 18, 2015 is considered an affected facility regardless of this provision. §60.5370 W hen 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.Page 11 of 160

(b) The provisions for exemption from compliance during periods of startup, shutdown a nd 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. (d) You are deemed to be in compliance with this subpart if you are in compliance with all applicable provisions of subpart

OOO Oa of this part. §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 th is 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 afterPage 12 of 160

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

p aragraphs (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 sect ion. (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 anothe r 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 flowbackPage 13 of 160

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 o r 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 s afely 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.Page 14 of 160

(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) Ea ch 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 techn ically 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 reliablePage 15 of 160

continuous ignition sourc e. You must also comply with paragraphs (a)(4) and (b) through (e) of this section. (3) You must maintain records specified in §60.5420(c)(1)(iii) for wildcat, delineation and low pressure gas wells. §60.5380 What standards apply to centrifugal compressor affected facilities ? You must comply with the standards in paragraphs (a) through (d) of this section for each centrifugal compressor affected facility. (a)(1) You must reduce VOC emissions from each centrifugal compressor wet seal fluid degassing system b y 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 requir ements 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 d emonstrate initial compliance with the standards that apply to centrifugal compressor affected facilities as required by §60.5410(b).Page 16 of 160

(c) You must demonstrate continuous compliance with the standards that apply to centrifugal compressor affected facilities as required by §60.5415(b). (d) You must perform the required notification, recordkeeping, and reporting as required by §60.5420. §60.5385 What standards apply to reciprocating compressor affected facilities? You must comply with the standards in paragrap hs (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 th is 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 pa cking has not yet been replaced.Page 17 of 160

(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 reci procating compressor affected facilities as required by §60.5415. (d) You must perform the required notification, recordkeeping, and reporting as required by §60.5420. §60.5390 What standards apply to pneumatic controller affected facilities? For each pneu matic 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 th is 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 greaterPage 18 of 160

than the applicable standar d 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 co ntroller 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 req uired 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 a n 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 natura l gasPage 19 of 160

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 pneumat ic controller affected facilities as required by §60.5415. (f) You must perform the required notification, recordkeeping, and reporting as required by §60.5420, except that you are not required to submit the notifications specified in §60.5420(a). §60.5395 What standards apply to storage vessel affected facilities? Except as provided in paragraph (h) of this section, you must comply with the standards in this section for each storage vessel affected facility. (a)(1) If you are the owner or operator of a Gro up 1 storage vessel affected facility, you must comply with paragraph (b) of this section.Page 20 of 160

(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 a ffected 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 t he 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 specif ied 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 redu ctions by April 15, 2014, or within 60 days after startup, whichever is later,Page 21 of 160

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 fac ilities 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 1 5, 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 tha t 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.Page 22 of 160

(i) If a well feeding the storage vessel affected facility undergoes fracturing or refracturing, you must comply with

par agraph (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 y our 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 day s 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 t hat 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 alternati ve 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 thePage 23 of 160

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

a ffected 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 a ffected 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, conde nsate, 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.Page 24 of 160

(2) If a storage vessel identified in paragraph (f)(1)(ii) of this sect ion 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 repo rting as required by §60.5420. (h) Exemptions. This subpart does not apply to storage vessels subject to and controlled in accordance with the requirements for storage vessels in 40 CFR part 60, subpart Kb, 40 CFR part 63, subparts G, CC, HH, or WW. §60.54 00 What equipment leak standards apply to affected facilities at an onshore natural gas processing plant?Page 25 of 160

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

- 1 a(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 byPage 26 of 160

weight. For a piece of equipment to be considered in wet gas service, it must be determined that it contain s 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 fol lowing 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 p rovided 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.Page 27 of 160

(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 locate d 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 requi rements 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 pla nt 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

- 1 1a(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/vaporPage 28 of 160

service, and connectors in gas/vapor service and in light liquid service within a process uni t 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 evaporat ed 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 calibr ation 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 appen dix 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).Page 29 of 160

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 calibra tion 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

mor e 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 th e percent of positive drift/divided by 100) may be re

monitored. §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 emissi on 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 per mitting the use of that alternative means for the purpose of compliance with thatPage 30 of 160

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 se ction 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 Ad ministrator 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 perio d 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 ac hieve 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 ?Page 31 of 160

(a) During the initial performance test required by §60.8(b), you must achieve at a minimum, an SO 2 emission reduction efficiency (Z i ) 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

SO 2 emission reduction efficiency (Z c ) to be determined from Table 2 of this subpart based on the sulfu r 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 performanc e 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 SO 2 emissions as required in §60.5405(a) and (b) as follows: (1) The average sulfur feed rate (X) must be computed as follows: X = K Q a YPage 32 of 160

Where: X = average sulfur feed rate, Mg/D (LT/D). Q a = average volumetric flow rate of acid gas from sweetening unit, dscm/day (dscf/day). Y = average H 2 S 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 −3 Mg/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 continuo us readings from the process flowmeter to determine the average volumetric flow rate (Q a ) 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 follo wing ASTM E260

- 96 (incorporated by reference as specified in §60.17) to determine the H 2 S 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 H 2 S 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 (Z i ) and continuous (Z c ) reduction efficiencies of SO 2 emissions.Page 33 of 160

(c) You must determine compliance with the SO 2 standards in §60.54 05(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: R = ( 100 S ) / ( S + E ) (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 densit y 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: E = C e Q sd / K 1 Where: E = emission rate of s ulfur per run, kg/hr. C e = concentration of sulfur equivalent (SO 2+ reduced sulfur), g/dscm (lb/dscf). Q sd = volumetric flow rate of effluent gas, dscm/hr (dscf/hr). K 1 = conversion factor, 1000 g/kg (7000 gr/lb). (4) The concentration (C e ) of sulfur equi valent must be the sum of the SO 2 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 ofPage 34 of 160

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 m 2 (54 ft 2 ) or at a point no closer to the walls than 1 m (39 in) if the cross sectional area is 5 m 2 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 SO 2 concentration. You must take eight samples of 20 minutes each at 30

- minu te 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 th e 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 ft 3 /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 10Page 35 of 160

(manual portion only) (incorporated by reference as specified in §60.17) to determine t he 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 con centration 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 a rithmetic average of the two measurements must be used to calculate the volumetric flow rate (Q sd ) 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 ave rage of the two runs must be the moisture content for the run.Page 36 of 160

§ 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 a ffected 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 operation s 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 me thod must be designed to be accurate within ±2 percent of the 24

- hour sulfur accumulation. (2) The H 2 S 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 usi ng the equation specified in §60.5406(b)(1). The Administrator may require you to demonstrate that the H 2 S concentration obtained from one orPage 37 of 160

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 H 2 S 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 aci d 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 H 2 S 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 achiev ed 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:Page 38 of 160

(1) A continuous monitoring system to measure the total sulfur emission rate (E) of SO 2 in the gases discharged to the atmosphere. The SO 2 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 SO 2 ) 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 determinePage 39 of 160

total sulfur emissions. At all times during the operation of the facility, you must maintain the avera ge 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 o f 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 mon itoring 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 monitorin g system to measure the emissionPage 40 of 160

rate of reduced sulfur compounds as SO 2 equivalent in the gases discharged to the atmosphere. The SO 2 equivalent compound emission rate must be expressed in terms of equivalent sulfur mass flow rates (kg/hr (lb/hr)). The sp an 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 em ission 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 sulfurPage 41 of 160

emission rate (E). The monitoring system must provide at least one data point in each successive 15

- minute interval. You must use at least t wo data points to calculate each 1

- hour average. You must use a minimum of 18 1

- hour averages t o 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 H 2 S expressed as sulfur may calculate the sulfur emission reduction efficiency achieved for each 24

- hour period by:

R = K 2 S X Where: R = The sulfur dioxide removal efficiency achieved during the 24

- hour period, percent. K 2 = 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 emissionPage 42 of 160

monitoring s ystem 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 o ptional 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 H 2 S 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 mo re 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

- wa y 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.Page 43 of 160

(c) Reagents. (1) Iodin e 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 br own 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 H 2 S 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

pressur e, and close (F). Open (G), bring liquid level down to 10 ml mark by lowering (L). Close (G), clamp rubber tubing near (E)Page 44 of 1 60

and disconnect it from burette. Rinse graduated cylinder with a standard iodine solution (0.00171 g I per ml); fill cylinder and

reco rd 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 H 2 S 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 H 2 S

- free gas or air, is required.Page 45 of 160

Figure 1 . Tutwil er burette (lettered items mentioned in text).Page 46 of 160

§ 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 f acility 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).Page 47 of 160

(3) You must main tain 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 ret aining 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 fi le 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

occur red 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 centr ifugal compressor affected facility you must reduce VOC emissions from each centrifugal compressor wet seal fluidPage 48 of 160

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 cont rol 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 inPage 49 of 160

§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 st andards 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 h ours 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 cl osed 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.Page 50 of 160

(1) Yo u 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 facili ties 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 requ irements of §60.5420(b).Page 51 of 160

(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 SO 2 specified in §60.5405(a), during the initial performance test as required by §60.8, the minimum required sulfur dioxide emission reduction efficiency (Z i ) is compared to the emission redu ction efficiency (R) achieved by the sulfur recovery technology as specified in paragraphs (g)(1)(i) and (ii) of this section. (i) If R ≥ Z i , your affected facility is in compliance. (ii) If R < Z i , 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 forPage 52 of 160

your sweetening unit affected facilities at onshore natural gas processing plants. (h) For each storage vessel affected facility, you mu st 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

ve ssel 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 affecte d facility.Page 53 of 160

(i) For each Group 1 storage vessel affected facility, you must submit the notification specified in §60.5395(b)(2) with the initial annual report specified in §60.5420(b)(6). §60.5411 What additional requirements must I meet to determine initi al compliance for my covers and closed vent systems routing materials from storage vessels 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 meet s 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 th is section if the closed vent system contains one or more bypass devices that could be used to divertPage 54 of 160

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 . Set the flow indicator to trigger an audible alarm, and initiate notification via remote alarm to the nearest field office, 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. You must maintain records of each time the alarm is activated according to §60.5420(c)(8). (B) You must secure th e bypass device valve installed at the inlet to the bypass device in the non

- diverting position using a car

- seal or a lock

- and

- key type configuration. (ii) Low leg drains, high point bleeds, analyzer vents,

open - ended valves or lines, and safety devices ar e 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 allPage 55 of 160

openings on the cover ( e.g . , access hatches, sampling ports,

p ressure 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 open ings 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 th ief hatch shall be equipped, maintained and operated with a weighted mechanism or equivalent, to ensure that the lid remains properly seated. You must selectPage 56 of 160

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

t he 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 inspe ctions. 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 o r 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 processPage 57 of 160

to the atmosphere . Set the flow indicator to trigger an audible alarm and that sounds an alarm, or , initiate s 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 contro l device or process to the atmosphere. You must maintain records of each time the alarm is activated according to §60.5420(c)(8). (B) You must secure the bypass device valve installed at the inlet to the bypass device in the non

- diverting position using a car - seal or a lock

- and

- key type configuration. (ii) Low leg drains, high point bleeds, analyzer vents,

open - ended valves or lines, and safety devices are not subject to the requirements of paragraph (c)(3)(i) of this section. §60.5412 What additional requi rements 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 con trol 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 faci lity must be installed according to paragraphsPage 58 of 160

(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 reduc e 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 t o a level equal to or less than 20 6 00 parts per million by volume as propane 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 bo iler or process heater.Page 59 of 160

(2) Each vapor recovery device ( e.g . , carbon adsorption system or condenser) or other non

- destructive control device must be designed and operated to reduce the mass content of VOC in the gases vented to the device by 95.0 percent b y 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 s pecified 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 u nder §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 mustPage 60 of 160

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, predete rmined 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 identify ing 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.Page 61 of 160

(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 o perating 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 fina l 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 ins talled according to paragraphs (d)(1)Page 62 of 160

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 §60.54 13(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 i n paragraphs (d)(1)(i) through ( iii iv ) 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 b y 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 inspe ction and maintenance plan, to return the unit to compliant operation. All inspection, repair and maintenance activities forPage 63 of 160

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. (iv) Each combustion control 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 ) through ( D ) of this section. ( A ) You must reduce the mass content of methane and 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. ( B ) 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 6 00 parts per million by volume as p ropane on a dry basis corrected to 3 percent oxygen as determined in accordance with the requirements of §60.5413. ( C ) 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.Page 64 of 160

( D ) 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 adsor ption system or condenser) or other non

- destructive control device must be designed and operated to reduce the mass content of VOC in the gases vented to the device by 95.0 percent by weight or greater. A carbon replacement schedule must be included in the design of the carbon adsorption system. (3) You must operate each control device used to comply with this subpart at all times when gases, vapors, and fumes are vented from the storage vessel affected facility through the closed vent system to the control device. You may vent more than one affected facility to a control device used to comply with this subpart. §60.5413 What are the performance testing procedures for control devices used to demonstrate compliance at my storage vessel or centrifugal compress or 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, youPage 65 of 160

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.Page 66 of 160

(5) A hazardous waste incinerator for which you have been issued a final permit under 40 CFR part 270 and comply with the requi rements 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 t o 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 paragraph s (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 speci fied 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 M ethods 1 and 1A do not apply to this section.Page 67 of 160

(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 specifie d 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 determin e 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 2 5A 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 pe r 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:Page 68 of 160

E i = K

2 ( ∑ C ij M ij n

j = 1 ) Q i

E o = K

2 ( ∑ C oj M oj n

j = 1 ) Q o

Where: E i , E o = Mass rate of TOC (minus methane and ethane) at the inlet and outlet of the control device, respectively, dry basis, kilogram per hour

. K 2 = 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. C ij , C oj = 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. M ij , M oj = Molecular weight of sample component j of the gas stream at the inlet and outlet of the control device, respectively, gram/gram

- mole. Q i , Q o = F lowrate 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 ethan e) 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:

R cd = E i − E o

E i ∗ 100 %Page 69 of 160

Where: R cd = Control efficiency of control device, percent. E i = 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. E o = 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 capac ity less than 44 megawatts is introduced with the combustion air or as a secondary fuel, you must determine the weight

- percent reduction of total TOC (minus methane and ethane) across the device by comparing the TOC (minus methane and ethane) in all combus ted 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 th e 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 sec tion. (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.Page 70 of 160

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

C TOC = ∑ ( ∑ C ji n j = i )

x x

i = 1 Where: C TOC = Concentration of total organic compounds minus methane and ethane, dry basis, parts per million by volume. C ji = Concentration of sample component j of sample i, dry basis, parts per million b y 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 ra te 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 spe cified 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:

C c = C m ( 17

. 9 20

. 9

− % O 2 d )

Where:Page 71 of 160

C c = TOC concentration corrected to 3 percent oxygen, dry basis, parts per million by volume. C m = TOC concentration, dry basis, parts per million by volume. %O 2d = 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.Page 72 of 160

(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)

o f 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 re quirements 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

con centration 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 afterPage 73 of 160

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, a nd 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 work ing 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 representa tive 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 manufa cturer must demonstrate that a specific model of control device achieves the performancePage 74 of 160

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 te st 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 parag raphs (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 r ate 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 thePage 75 of 160

maximum design rate. Hold at 70 percent for 5 minutes. In the 10

- 15 minute tim e 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 sam pling. (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 i ncluded 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.Page 76 of 160

(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.Page 77 of 160

(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 (H 2 ), carbon monoxide (CO), carbon dioxide (CO 2 ), nitrogen (N 2 ), oxygen (O 2 ) 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 acc ordance 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 st ack 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 forPage 78 of 160

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 accur ate 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.Page 79 of 160

(B) Purge th e 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 v alid. 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 concen tration 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

Me thod 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 durin g the port change.Page 80 of 160

(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 t he 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 i n 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 travers ed 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 b y 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 forPage 81 of 160

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 cor rected to 3 percent CO 2 , as measured by Method 3C, 40 CFR part 60, appendix A

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

C corr = C meas ( 3 CO 2meas )

Where: C meas = The measured concentration of the pollutant. CO 2meas = The measured concentration of the CO 2 diluent. 3 = The corrected reference concentration of CO 2 diluent. C corr = 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

anno tated 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.Page 82 of 160

(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 v isible 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 CO 2 . (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 CO 2 . (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 flo w 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 co ntrol 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.Page 83 of 160

(12) The owner or operator of a combustion control device model tested un der 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 paragr aphs (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 t emperature 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.Page 84 of 160

(K) T ip 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 cert ification, 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.Page 85 of 160

(3) Devices must be operated with no visible emissions, except for periods not to exceed a total of 2 1 minute s during

any hour 15

- minute period . A visible emissions test using

c onducted according to 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 each calendar quarter . The observation period shall be 15 minutes must be 1 h our 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 i nspection 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 ma intenance 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 testPage 86 of 160

results for that model of combustion control device are posted at the following Web site: epa.gov/a irquality/oilandgas/

. (7) Ensure that each enclosed combustion device is maintained in a leak free condition. §60.5415 How do I demonstrate continuous compliance with the standards for my gas well affected facility, my centrifugal compressor affected facil ity, 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 con tinuous 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 requirementsPage 87 of 160

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 leas t 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 s ite 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 rat e 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 §60.54 13(d), compliance withPage 88 of 160

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 moni toring 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. Y ou 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, r epairs 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 co llection periods to assess the operation of the control device and associated control system.Page 89 of 160

(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 operati on. (B) Devices must be operated with no visible emissions, except for periods not to exceed a total of 2 1 minute s during

any 15

- minute period hour . A visible emissions test using conducted according to section 11

. of 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 each calendar quarter . The observation period shall be 15 minutes must be 1 hour and must be conducted according to section 11. of EPA Method 22, 40 CFR par t 60, appendix A

. (C) Devices failing the visible emissions test must follow manufacturer's repair instructions, if available, or bestPage 90 of 160

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 de monstrate 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

t emperature 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 perfo rmance curve established under paragraph (b)(2)(viii)(A) of this section.Page 91 of 160

(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 reducti on, 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 t o 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 d ays or more of operation, you have demonstrated compliance with the TOC emission reduction if the rolling 365

- day average TOC emission reduction calculated inPage 92 of 160

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 p aragraphs (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 nu mber of months since the most recent rod packing replacement reaches 36 months.Page 93 of 160

(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 w hich 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 m ust 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 continuousPage 94 of 160

compliance with the performance requirements of §60.5412(d) for each storage vessel affect ed 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 contro l 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 y ou 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 SO 2 specified in §60.5405(b) according to par agraphs (g)(1) and (2) of this section. (1) The minimum required SO 2 emission reduction efficiency (Z c ) is compared to the emission reduction efficiency (R) achieved by the sulfur recovery technology. (i) If R ≥ Z c , your affected facility is in compliance. (ii) If R < Z c , your affected facility is not in compliance.Page 95 of 16 0

(2) The emission reduction efficiency (R) achieved by the sulfur reduction technology must be determined using the procedures in §60.5406(c)(1). §60.5416 What are the initial and continuous cove r and closed vent system inspection and monitoring requirements for my storage vessel and centrifugal compressor affected facility? For each closed vent system or cover at your storage vessel, centrifugal compressor and reciprocating compressor affected fa cility, 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 pro vided 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 spec ified in paragraph (a)(3) of this section, and inspect each bypass device according to the procedures of paragraph (a)(4) of this section. (1) For each closed vent system joint, seam, or other connection that is permanently or semi

- permanently sealed ( e.g. , 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.Page 96 of 160

(i) Conduct an initial inspection according to the test methods and pr ocedures 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 connect ion 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 i nitial inspection according to the test methods and procedures specified in paragraph (b) of this section to demonstrate that the closed vent system operates withPage 97 of 160

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 visua l 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 closu re 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 thosePage 98 of 160

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 secti on 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 i n §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 th e bypass device that could divert the steam away from the control device to the atmosphere. (ii) If the bypass device valve installed at the inlet to the bypass device is secured in the non

- diverting position using

a car - seal or a lock

- and

- key type configu ration, 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 inspection s according to §60.5420(c)(8).Page 99 of 160

(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 f or 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 par agraphs (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.Page 100 of 160

(5) You may choose to adjust or not ad just 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 m eet 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 compou nd 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 instrume nt 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, calculatedPage 101 of 160

on an inert

- free basis, as descr ibed 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 speci fied 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 i nterface 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.Page 102 of 160

(9) Repairs. In the event that a leak or defect is detect ed, 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 all owed 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 equipme nt 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 pa rts 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 orPage 103 of 160

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. (1 3) 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 inspe ct 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) ofPage 104 of 160

this section, and inspect each bypass device ac cording 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, yo u 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 aud itory inspections for defects that could result in air emissions. Defects include, but are not limited to, visible cracks, holes, or gaps in the cover,Page 105 of 160

or between the cover and the separator wall; broken, cracked, or otherwise damaged seals or gaskets on c losure 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 gr ound 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 byp ass 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) You must properly install, calibrate and maintain a flow indicator at the inlet to the bypass device that could di vert the stream away from the control device or process to the atmospher e . Set the flow indicator to trigger an audible alarm, and initiate notification via remote alarm to the nearest field office, when the bypass device is open such that the sound an ala rm at the inlet to the bypass device when the stream is being , or could be, diverted away from the control device or process to the atmosphere. You must maintain records of each time the alarm is sounded activated according to §60.5420(c)(8).Page 106 of 160

(ii) If the b ypass device valve installed at the inlet to the bypass device is secured in the non

- diverting position using

a car - seal or a lock

- and

- key type configuration, visually inspect the seal or closure mechanism at least once every month to verify that the valve is maintained in the non

- diverting position and the vent stream is not diverted through the bypass device. You must maintain records of the inspections and records of each time the key is checked out, if applicable, according to §60.5420(c)(8). (4) Repair s. 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 deterior ating 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 aPage 107 of 160

shutdown, o r 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 requirem ents. 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 requir ements 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.Page 108 of 160

(i) You determine that the equipment cannot be inspected without elevating the inspecting personnel more than 2 meters above a support surface. (ii) You have a written plan that requires inspection of the equipment at least once every 5 years. §60.5417 What are the continuous control device monitoring requirements for my storage vessel or centrifugal compressor affected facility? You must meet the applicable requirements of this section to demonstrate continuous compliance for each control device used to meet emission standards for your storage vessel or centrifugal compressor af fected 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 sp ecified 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 sec tion. (b) You are exempt from the monitoring requirements specified in paragraphs (c) through (g) of this section for thePage 109 of 160

control devices listed in paragraphs (b)(1) and (2) of this section. (1) A boiler or process heater in which all vent streams are intr oduced 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 sectio n. (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 minut e 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 mustPage 110 of 160

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 th e 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 r eporting 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 ma intain a device equipped with a continuous recorder to measure the valuesPage 111 of 160

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

tem perature 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 locati ons 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.Page 112 of 160

(iii) For a flare, a heat sensing monitoring device equipped with a continuous recorder that indicates the continuous ignition of the pilot fla me. (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 min imum 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.Page 113 of 160

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 c ontinuous 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) an d (B) of this section.Page 114 of 160

(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, c alibrate, 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 Administrat or 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 unitPage 115 of 160

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 con ditions 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

oper ating 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 orPage 116 of 160

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 param eter 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 m anufacturer. (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 r equirements 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 inPage 117 of 160

§60.5412(a), then t he 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 contr ol 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 cr iteria 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 criteri on 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 l ess than the minimum operating parameter limit (or, if applicable, greater than the maximumPage 118 of 160

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 ef ficiency 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 accordi ng 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 lin e 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 clos ure mechanism has been broken, the bypassPage 119 of 160

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 occ urs 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) oc curs. (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 continu ous 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 c alendar days.Page 120 of 160

(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 mi nute 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 l east once every calendar month to ensurePage 121 of 160

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 manuf acturer'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 b e available for inspection as specified in §60.5420(c)(13). (4) Conduct a periodic performance test no later than 60 months after the initial performance test as specified in §60.5413(b)(5)(ii) and conduct subsequent periodic performance tests at intervals no longer than 60 months following the previous periodic performance test

. §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 ow n 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 compre ssor or storagePage 122 of 160

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 co ordinates 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 thi s section. The initial annual report is due no later than 90 days after the end of the initial compliance period as determinedPage 123 of 160

according to §60.5410. Subsequent annual reports are due no later than same date each year as the initial annual report. If

you o wn 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 coincid e 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 repo rting 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 an d 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.Page 124 of 160

(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 h ydraulic 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 report ing 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 reconstruct ed 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.Page 125 of 160

(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 Octo ber 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 contro ller 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 inf ormation 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) Rec ords of deviations specified in paragraph (c)(4)(v) of this section that occurred during the reporting period.Page 126 of 160

(6) For each storage vessel affected facility, the information in paragraphs (b)(6)(i) through (vii) of this section. (i) An identification, incl uding 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 re porting 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 sto rage 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 America n Datum of 1983.Page 127 of 160

(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 storag e 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 per formance 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 t o the EPA's Central Data Exchange (CDX) ( https://cdx.epa.gov/ ). Only data collected using test methodsPage 128 of 160

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 t hat 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 (includin g, 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

spe cified 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. 4Page 129 of 160

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 14 ) 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 affectedPage 130 of 160

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 facilit y 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 direc t 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 h ours 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 recover y 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 ofPage 131 of 160

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 req uired 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) Record s 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 reciproca ting compressor rod packing replacement, or date of installation of aPage 132 of 160

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

s pecifications 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 a nd 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 stan dard 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.Page 133 of 160

(v) Records of deviations in cases where the pneumatic controller was not operate d 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 se ction. (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 v essel 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 r equirements 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 storagePage 134 of 160

segment. If a storage vessel is removed from a site and, within 30 days, is eithe r 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 a dded 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 centrif ugal 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 requirement s 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 cl osed 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).Page 135 of 160

(10) For each centrifugal compressor affected facility, records of the s chedule 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 requiremen ts 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' opera ting 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 per formingPage 136 of 160

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 in cluding 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. (14) A log of records as specified in §§60.5412(d)(1 ) (iii) and 60.5413(e)(4) for all inspection, repair and maintenance activities for each control device s failing the visible emissions test. §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 requ irements 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 id entification onPage 137 of 160

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

l ocation: (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.Page 138 of 160

(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 emis sions 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 req uirements 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 own er 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 pres sure 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).Page 1 39 of 160

(c) An owner or operator must include the following information in all semiannual reports in ad dition 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). §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 a nnual 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

l ess 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 whichPage 140 of 160

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 tha n 2 LT/D of H 2 S in the acid gas (expressed as sulfur) you must keep, for the life of the facility, an analysis dem onstrating that the facility's design capacity is less than 2 LT/D of H 2 S 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 H 2 S 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 alter native 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.Page 141 of 160

§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 n ot 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 (H 2 S) and carbon dioxide (CO 2 ) 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. Capital expe nditure means, in addition to the definition in 40 CFR 60.2, an expenditure for a physical or operational change to an existing facility that: (1) Exceeds P, the product of the facility's replacement cost, R, and an adjusted annual asset guideline repairPage 142 of 160

a llowance, A, as reflected by the following equation: P = R × A, where (i) The adjusted annual asset guideline repair allowance, A, is the product of the percent of the replacement cost, Y, and the applicable basic annual asset guideline repair allowance, B , divided by 100 as reflected by the following equation: A = Y × (B ÷ 100); (ii) The percent Y is determined from the following equation: Y = 1.0 − 0.575 log X, where X is 201 1 minus the year of construction; and (iii) The applicable basic annual asset guideline repair allowance, B, is 4.5. 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 centrif ugal 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 perso n who performs similar policy or decision

- making functions for the corporation, or a duly authorized representative of such person if thePage 143 of 160

representative is responsible for the overall operation of one or more manufacturing, production, or operating facilit ies 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 s ole 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 execu tive 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 thePage 144 of 160

Clean Air Act or the regulations promulgated thereunder are

concer ned; 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 c onveys 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

pr oduction 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.

C ondensate 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 pr ocess control device ( e.g. , level control, temperature control, pressure control) where the supply gas pressure is modulated by the process condition, and thenPage 145 of 160

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 loadin g 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 a n 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, o perating limit, or work practice standard in this subpart during startup, shutdown,Page 146 of 160

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 fl ange 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 m eans 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 g as well following a treatment, either in preparation for a subsequent phase of treatment or inPage 147 of 160

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 du ring 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 permanentl y 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, mod ification or reconstruction has commenced after August 23, 2011, and on or before April 12, 2013.Page 148 of 160

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 , and on or before September 18, 2015

. 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 hydraul ic 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 contain s 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.

Inter mediate hydrocarbon liquid means any naturally occurring, unrefined petroleum liquid.Page 149 of 160

Intermittent/snap

- action pneumatic controller means a pneumatic controller that vents non

- continuously. Liquefied natural gas unit means a unit used to cool natural gas t o 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 true 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 e mploying 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 f ield 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 d epression valve, or an isolated or standalone Joule

Thompson skid is not a natural gas processing plant.Page 150 of 160

Natural gas transmission means the pipelines used for the long distance transport of natural gas (excluding processing). Specific equipment used in nat ural 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 p urchased 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

- dr iven 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 se as 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 l iquids or gases and is designed not to vent to the atmosphere as a result of compression of the vapor headspace inPage 151 of 160

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. Reciproc ating 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 tha t 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.Page 152 of 160

Recovered liquids means an y 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. Reduc ed sulfur compounds means H 2 S, carbonyl sulfide (COS), and carbon disulfide (CS 2 ). 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 acc ordance 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 simila r 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 onePage 153 of 160

or more manufacturing, production, or operating facilities applying for or s ubject 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 adv ance 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 offic ial. 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 represent ative for any other purposes under part 60.Page 154 of 160

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 or has been used to replace any stora ge 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 materi als 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 flowb ack 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 recoveryPage 155 of 160

of salable quality gas and separation and recovery of any crude oil, condensate or produced water. Storage ve ssel 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. 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 ves sel 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 a re 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 firstPage 156 of 160

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 SO 2 equivalents means the sum of volumetric or mass concentrations of the sulfur compounds obtained by adding the quantity existing as SO 2 to the quantity of SO 2 that would bePage 157 of 160

obtained if all red uced sulfur compounds were converted to SO 2 (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 flui ds 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 t o 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 co mpletion 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 star tup of production following flowback for a period which exceeds 60 days is considered a storage vessel under this subpart.Page 158 of 160

Well site means one or more areas that are directly disturbed during the drilling and subsequent operation of, or affected by, produc tion 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 well head 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. § §60.5431 – 60.5499 [Reserved] Table 1 to Subpart OOOO of P art 60

– Required Minimum Initial SO 2 Emission Reduction Efficiency (Z i )

H 2 S content of acid gas (Y), % Sulfur fee d rate (X), LT/D

2.0 < X < 5.0 5.0<X < 15.0 15.0<X < 300.0 X>300.0 Y > 50 79.0 88.51X 0.0101 Y 0.0125 or 99.9, whichever is smaller 20 < Y<50 79.0 88.5 1 X 0.0101 Y 0.0125 or 97.9, whichever is smaller 97.9 10 < Y<20 79.0 88.5 1 X 0.0101 Y 0.0125 or 93.5 , whichever is smaller 9 3.5 93.5

Y<10 79.0 79.0 79.0 79.0Page 159 of 160

Table 2 to Subpart OOOO of P art 60

– Required Minimum SO 2 Emission Reduction Efficiency (Z c )

H 2 S content of acid gas (Y), % Sulfur feed rate (X), LT/D

2.0 < X < 5.0 5.0<X < 15.0 15.0<X < 300.0 X>300.0 Y > 50 74.0 85.35X 0.0144 Y 0.0128 or 99.9, whichever is smaller 20 < Y<50 74.0 85.35X 0.0144 Y 0.0128 or 97.5 , whichever is smaller 97.5 10 < Y<20 74.0 85.35X 0.0144 Y 0.0128 or 90.8, whichever is smaller 90.8 90.8

Y<10 74.0 74.0 74.0 74.0 X = The sulfur feed rate from the sweetening un it ( i.e. , the H 2 S 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 H 2 S (dry basis) rounded to one decimal place. Z = The minimum requ ired sulfur dioxide (SO 2 ) emission reduction efficiency, expressed as percent carried to one decimal place. Z i refers to the reduction efficiency required at the initial performance test. Z c refers to the reduction efficiency required on a continuous basis after compliance with Z i has been demonstrated. Table 3 to Subpart OOOO of P art 60

– Applicability of General Provisions to Subpart OOOO As stated in §60.5425, you must comply with the following applicable General Provisions:
General Provisions Citatio n 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 YesPage 160 of 160

§60.5 Determination of

co nstruction 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 stor age 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 M onitoring

requirements Yes Continuous monitors are required for storage vessels §60.14 Modification Yes §60.15 Reconstruction Yes Except that §60.15(d) does not apply to pneumatic controllers, centrifugal compressors or storage vessels. §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