Title 40—Protection of Environment--Volume 1
PART 60—STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
§ 60.5430b   What definitions apply to this subpart?
As used in this subpart, all terms not defined herein shall have the meaning given them in the Act or in subpart A of this part; and the following terms shall have the specific meanings given them.
Access to electrical power means commercial line power is available onsite, with sufficient capacity to support the required power loading of onsite equipment, and which provides reliable and consistent power.
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.
Artificial lift equipment means mechanical pumps including, but not limited to, rod pumps and electric submersible pumps used to flowback fluids from a well.
Associated gas means the natural gas from wells operated primarily for oil production that is released from the liquid hydrocarbon during the initial stage of separation after the wellhead. Associated gas production begins at the startup of production after the flow back period ends. Gas from wildcat or delineation wells is not associated gas.
Average aggregate detection threshold means:
(1) For the purposes of § 60.5398b, the average of all site-level detection thresholds from a single deployment ( e.g., a singular flight that surveys multiple well sites, centralized production facility, and/or compressor stations) of a technology; and
(2) For the purposes of § 60.5371b, the average of all site-level detection thresholds from a single deployment in the same basin and field.
Bleed rate means the rate in standard cubic feet per hour at which natural gas is continuously vented (bleeds) from a process controller.
Capital expenditure means, as an alternative 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 repair allowance, 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 = (CPI of date of construction/most recently available CPI of date of project), where the “CPI-U, U.S. city average, all items” must be used for each CPI value; and
(iii) The applicable basic annual asset guideline repair allowance, B, is 4.5.
(2) [Reserved]
Centralized production facility means one or more storage vessels and all equipment at a single surface site used to gather, for the purpose of sale or processing to sell, crude oil, condensate, produced water, or intermediate hydrocarbon liquid from one or more offsite natural gas or oil production wells. This equipment includes, but is not limited to, equipment used for storage, separation, treating, dehydration, artificial lift, combustion, compression, pumping, metering, monitoring, and flowline. Process vessels and process tanks are not considered storage vessels or storage tanks. A centralized production facility is located upstream of the natural gas processing plant or the crude oil pipeline breakout station and is a part of producing operations.
Centrifugal compressor means any machine for raising the pressure of a natural gas by drawing in low pressure natural gas and discharging significantly higher-pressure natural gas by means of mechanical rotating vanes or impellers. Screw, sliding vane, and liquid ring compressors are not centrifugal compressors for the purposes of this subpart.
Centrifugal compressor equipped with sour seal oil separator and capture system means a wet seal centrifugal compressor system which has an intermediate closed process that degasses most of the gas entrained in the sour seal oil and sends that gas to either another process or combustion device ( i.e., degassed emissions are recovered). The de-gas emissions are routed back to a process or combustion device directly from the intermediate closed degassing process; after the intermediate closed process the oil is ultimately recycled for recirculation in the seals to the lube oil tank where any small amount of residual gas is released through a vent.
Certifying official means one of the following:
(1) For a corporation: A president, secretary, treasurer, or vice-president of the corporation in charge of a principal business function, or any other person who performs similar policy or decision-making functions for the corporation, or a duly authorized representative of such person if the representative is responsible for the overall operation of one or more manufacturing, production, or operating facilities with an affected facility subject to this subpart and either:
(i) The facilities employ more than 250 persons or have gross annual sales or expenditures exceeding $25 million (in second quarter 1980 dollars); or
(ii) The Administrator is notified of such delegation of authority prior to the exercise of that authority. The Administrator reserves the right to evaluate such delegation;
(2) For a partnership (including but not limited to general partnerships, limited partnerships, and limited liability partnerships) or sole proprietorship: A general partner or the proprietor, respectively. If a general partner is a corporation, the provisions of paragraph (1) of this definition apply;
(3) For a municipality, state, Federal, or other public agency: Either a principal executive officer or ranking elected official. For the purposes of this part, a principal executive officer of a Federal agency includes the chief executive officer having responsibility for the overall operations of a principal geographic unit of the agency ( e.g., a Regional Administrator of EPA); or
(4) For affected facilities:
(i) The designated representative in so far as actions, standards, requirements, or prohibitions under title IV of the CAA or the regulations promulgated thereunder are concerned; or
(ii) The designated representative for any other purposes under this part.
Closed vent system means a system that is not open to the atmosphere and that is composed of hard-piping, ductwork, connections, and, if necessary, flow-inducing devices that transport gas or vapor from a piece or pieces of equipment to a control device or back to a process.
Coil tubing cleanout means the process where an operator runs a string of coil tubing to the packed proppant within a well and jets the well to dislodge the proppant and provide sufficient lift energy to flow it to the surface. Coil tubing cleanout includes mechanical methods to remove solids and/or debris from a wellbore.
Collection system means any infrastructure that conveys gas or liquids from the well site to another location for treatment, storage, processing, recycling, disposal or other handling.
Completion combustion device means any ignition device, installed horizontally or vertically, used in exploration and production operations to combust otherwise vented emissions from completions. Completion combustion devices include pit flares.
Compressor mode means the operational and pressurized status of a compressor. For both centrifugal compressors and reciprocating compressors, “mode” refers to either: Operating-mode, standby-pressurized-mode, or not-operating-depressurized-mode.
Compressor station means any permanent combination of one or more compressors that move natural gas at increased pressure through gathering or transmission pipelines, or into or out of storage. This includes but is not limited to gathering and boosting stations and transmission compressor stations. The combination of one or more compressors located at a well site, centralized production facility, or an onshore natural gas processing plant, is not a compressor station for purposes of § 60.5365b(e) and § 60.5397b.
Condensate means hydrocarbon liquid separated from natural gas that condenses due to changes in the temperature, pressure, or both, and remains liquid at standard conditions.
Connector means flanged, screwed, or other joined fittings used to connect two pipe lines or a pipe line and a piece of process equipment or that close an opening in a pipe that could be connected to another pipe. Joined fittings welded completely around the circumference of the interface are not considered connectors for the purpose of this regulation.
Continuous bleed means a continuous flow of pneumatic supply natural gas to a process controller.
Crude oil and natural gas source category means:
(1) Crude oil production, which includes the well and extends to the point of custody transfer to the crude oil transmission pipeline or any other forms of transportation; and
(2) Natural gas production, processing, transmission, and storage, which include the well and extend to, but do not include, the local distribution company custody transfer station.
Custody meter means the meter where natural gas or hydrocarbon liquids are measured for sales, transfers, and/or royalty determination.
Custody meter assembly means an assembly of fugitive emissions components, including the custody meter, valves, flanges, and connectors necessary for the proper operation of the custody meter.
Custody transfer means the transfer of crude oil or natural gas after processing and/or treatment in the producing operations, or from storage vessels or automatic transfer facilities or other such equipment, including product loading racks, to pipelines or any other forms of transportation.
Dehydrator means a device in which an absorbent directly contacts a natural gas stream and absorbs water in a contact tower or adsorption column (absorber).
Delineation well means a well drilled in order to determine the boundary of a field or producing reservoir.
Deviation means any instance in which an affected source subject to this subpart, or an owner or operator of such a source:
(1) Fails to meet any requirement or obligation established by this subpart including, but not limited to, any emission limit, operating limit, or work practice standard;
(2) Fails to meet any term or condition that is adopted to implement an applicable requirement in this subpart and that is included in the operating permit for any affected source required to obtain such a permit; or
(3) Fails to meet any emission limit, operating limit, or work practice standard of this subpart during startup, shutdown, or malfunction, regardless of whether or not such failure is permitted by this subpart.
Distance piece means an open or enclosed casing through which the piston rod travels, separating the compressor cylinder from the crankcase.
Double block and bleed system means two block valves connected in series with a bleed valve or line that can vent the line between the two block valves.
Duct work means a conveyance system such as those commonly used for heating and ventilation systems. It is often made of sheet metal and often has sections connected by screw or crimping. Hard-piping is not ductwork.
Emergency shutdown device means a device which functions exclusively to protect personnel and/or prevent physical damage to equipment by shutting down equipment or gas flow during unsafe conditions resulting from an unexpected event, such as a pipe break or fire. For the purposes of this subpart, an emergency shutdown device is not used for routine control of operating conditions.
Equipment, as used in the standards and requirements of this subpart relative to the process unit equipment affected facility at onshore natural gas processing plants, means each pump, pressure relief device, open-ended valve or line, valve, and flange or other connector that has the potential to emit methane or VOC and any device or system required by those same standards and requirements of this subpart.
Field gas means feedstock gas entering the natural gas processing plant.
Field gas gathering means the system used transport field gas from a field to the main pipeline in the area.
First attempt at repair means an action taken for the purpose of stopping or reducing fugitive emissions to the atmosphere. First attempts at repair include, but are not limited to, the following practices where practicable and appropriate: Tightening bonnet bolts; replacing bonnet bolts; tightening packing gland nuts; or injecting lubricant into lubricated packing.
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 or a mainline pipeline.
Flowback means the process of allowing fluids and entrained solids to flow from a well following a treatment, either in preparation for a subsequent phase of treatment or in preparation for cleanup and returning the well to production. The term flowback also means the fluids and entrained solids that emerge from a well during the flowback process. The flowback period begins when material introduced into the well during the treatment returns to the surface following hydraulic fracturing or refracturing. The flowback period ends when either the well is shut in and permanently disconnected from the flowback equipment or at the startup of production. The flowback period includes the initial flowback stage and the separation flowback stage. Screenouts, coil tubing cleanouts, and plug drill-outs are not considered part of the flowback process.
Fuel gas means gases that are combusted to derive useful work or heat.
Fuel gas system means the offsite and onsite piping and flow and pressure control system that gathers gaseous stream(s) generated by onsite operations, may blend them with other sources of gas, and transports the gaseous stream for use as fuel gas in combustion devices or in-process combustion equipment, such as furnaces and gas turbines, either singly or in combination.
Fugitive emissions means, for the purposes of § 60.5397b, any indication of emissions observed from a fugitive emissions component using AVO, an indication of visible emissions observed from an OGI instrument, or an instrument reading of 500 ppmv or greater using Method 21 of appendix A-7 to this part.
Fugitive emissions component means any component that has the potential to emit fugitive emissions of methane or VOC at a well site, centralized production facility, or compressor station, such as valves (including separator dump valves), connectors, pressure relief devices, open-ended lines, flanges, covers and closed vent systems not subject to § 60.5411b, thief hatches or other openings on a storage vessel not subject to § 60.5395b, compressors, instruments, meters, and yard piping.
Gas to oil ratio (GOR) means the ratio of the volume of gas at standard temperature and pressure that is produced from a volume of oil when depressurized to standard temperature and pressure.
Hard-piping means pipe or tubing that is manufactured and properly installed using good engineering judgment and standards such as ASME B31.3, Process Piping (available from the American Society of Mechanical Engineers, P.O. Box 2300, Fairfield, NJ 07007-2300).
Hydraulic fracturing means the process of directing pressurized fluids containing any combination of water, proppant, and any added chemicals to penetrate tight formations, such as shale or coal formations, that subsequently require high rate, extended flowback to expel fracture fluids and solids during completions.
Hydraulic refracturing means conducting a subsequent hydraulic fracturing operation at a well that has previously undergone a hydraulic fracturing operation.
In gas/vapor service means that the piece of equipment contains process fluid that is in the gaseous state at operating conditions.
In heavy liquid service means that the piece of equipment is not in gas/vapor service or in light liquid service.
In light liquid service means that the piece of equipment contains a liquid that meets the conditions specified in § 60.5402b(d)(2) or § 60.5403b.
In vacuum service means that equipment is operating at an internal pressure which is at least 5 kilopascals (kPa) (0.7 psia) below ambient pressure.
In wet gas service means that a compressor or piece of equipment contains or contacts the field gas before the extraction step at a gas processing plant process unit.
Initial calibration value as used in the standards and requirements of this subpart relative to the process unit equipment affected facility at onshore natural gas processing plants means the concentration measured during the initial calibration at the beginning of each day required in § 60.5403b, or the most recent calibration if the instrument is recalibrated during the day ( i.e., the calibration is adjusted) after a calibration drift assessment.
Initial flowback stage means the period during a well completion operation which begins at the onset of flowback and ends at the separation flowback stage.
Intermediate hydrocarbon liquid means any naturally occurring, unrefined petroleum liquid.
Intermittent vent natural gas-driven process controller means a process controller that is not designed to have a continuous bleed rate but is instead designed to only release natural gas to the atmosphere as part of the actuation cycle.
Liquefied natural gas unit means a unit used to cool natural gas to the point at which it is condensed into a liquid which is colorless, odorless, non-corrosive and non-toxic.
Liquid collection system means tankage and/or lines at a well site to contain liquids from one or more wells or to convey liquids to another site.
Liquids dripping means any visible leakage from the seal, including spraying, misting, clouding, and ice formation.
Liquids unloading means the unloading of liquids that have accumulated over time in gas wells, which are impeding or halting production. Routine well maintenance activities, including workovers, screenouts, coil tubing cleanouts, or any other activity that requires a rig or other machinery are not considered liquids unloading.
Local distribution company (LDC) custody transfer station means a metering station where the LDC receives a natural gas supply from an upstream supplier, which may be an interstate transmission pipeline or a local natural gas producer, for delivery to customers through the LDC's intrastate transmission or distribution lines.
Low-e valve means a valve (including its specific packing assembly) for which the manufacturer has issued a written warranty or performance guarantee that it will not emit fugitives at greater than 100 ppm in the first five years. A valve may qualify as a low-e valve if it is as an extension of another valve that has qualified as a low-e valve.
Low-e packing means a valve packing product for which the manufacturer has issued a written warranty or performance guarantee that it will not emit fugitives at greater than 100 ppm in the first five years. Low-e injectable packing is a type of low-e packing product for which the manufacturer has also issued a written warranty or performance guarantee and that can be injected into a valve during a “drill-and-tap” repair of the valve.
Low pressure well means a well that satisfies at least one of the following conditions:
(1) The static pressure at the wellhead following fracturing but prior to the onset of flowback is less than the flow line pressure;
(2) The pressure of flowback fluid immediately before it enters the flow line, as determined under § 60.5432b, is less than the flow line pressure; or
(3) Flowback of the fracture fluids will not occur without the use of artificial lift equipment.
Major production and processing equipment means reciprocating or centrifugal compressors, glycol dehydrators, heater/treaters, separators, control devices, natural gas-driven process controllers, natural gas-driven pumps, and storage vessels or tank batteries collecting crude oil, condensate, intermediate hydrocarbon liquids, or produced water, for the purpose of determining whether a well site is a wellhead only well site.
Maximum average daily throughput means the following:
(1) The earliest calculation of daily average throughput, determined as described in paragraph (2) or (3) of this definition, to a tank battery over the days that production is routed to that tank battery during the 30-day PTE evaluation period employing generally accepted methods specified in § 60.5365b(e)(2).
(2) If throughput to the tank battery is measured on a daily basis ( e.g., via level gauge automation or daily manual gauging), the maximum average daily throughput is the average of all daily throughputs for days on which throughput was routed to the tank battery during the 30-day evaluation period; or
(3) If throughput to the tank battery is not measured on a daily basis ( e.g., via manual gauging at the start and end of loadouts), the maximum average daily throughput is the highest, of the average daily throughputs, determined for any production period to that tank battery during the 30-day evaluation period, as determined by averaging total throughput to that tank battery over each production period. A production period begins when production begins to be routed to a tank battery and ends either when throughput is routed away from that tank battery or when a loadout occurs from that tank battery, whichever happens first. Regardless of the determination methodology, operators must not include days during which throughput is not routed to the tank battery when calculating maximum average daily throughput for that tank battery.
Multi-wellhead only well site means a well site that contains two or more wellheads and no major production and processing equipment.
Natural gas-driven diaphragm pump means a positive displacement pump powered by pressurized natural gas that uses the reciprocating action of flexible diaphragms in conjunction with check valves to pump a fluid. A pump in which a fluid is displaced by a piston driven by a diaphragm is not considered a diaphragm pump for purposes of this subpart. A lean glycol circulation pump that relies on energy exchange with the rich glycol from the contactor is not considered a diaphragm pump.
Natural gas-driven piston pump means a positive displacement pump powered by pressurized natural gas that moves and pressurizes fluid by using one or more reciprocating pistons. A pump in which a fluid is displaced by a piston driven by a diaphragm is considered a piston pump for purposes of this subpart. A lean glycol circulation pump that relies on energy exchange with the rich glycol from the contactor is not considered a piston pump.
Natural gas-driven process controller means a process controller powered by pressurized natural gas.
Natural gas liquids means the hydrocarbons, such as ethane, propane, butane, and pentane that are extracted from field gas.
Natural gas processing plant (gas plant) means any processing site engaged in the extraction of natural gas liquids from field gas, fractionation of mixed natural gas liquids to natural gas products, or both. A Joule-Thompson valve, a dew point depression valve, or an isolated or standalone Joule-Thompson skid is not a natural gas processing plant.
Natural gas transmission means the pipelines used for the long-distance transport of natural gas (excluding processing). Specific equipment used in natural gas transmission includes the land, mains, valves, meters, boosters, regulators, storage vessels, dehydrators, compressors, and their driving units and appurtenances, and equipment used for transporting gas from a production plant, delivery point of purchased gas, gathering system, storage area, or other wholesale source of gas to one or more distribution area(s).
No detectable emissions means, for the purposes of § 60.5401b and § 60.5403b, that the equipment is operating with an instrument reading of less than 500 ppmv above background, as determined by Method 21 of appendix A-7 to this part.
No identifiable emissions means, for the purposes of covers, closed vent systems, and self-contained natural gas-driven process controllers and as determined according to the provisions of § 60.5416b, that no emissions are detected by AVO means when inspections are conducted by AVO; no emissions are imaged with an OGI camera when inspections are conducted with OGI; and equipment is operating with an instrument reading of less than 500 ppmv above background, as determined by Method 21 of appendix A-7 to this part when inspections are conducted with Method 21.
Nonfractionating plant means any gas plant that does not fractionate mixed natural gas liquids into natural gas products.
Non-natural gas-driven process controller means an instrument that is actuated using other sources of power than pressurized natural gas; examples include solar, electric, and instrument air.
Onshore means all facilities except those that are located in the territorial seas or on the outer continental shelf.
Open-ended valve or line or open-ended vent line means any valves, except safety relief valves, having one side of the valve seat in contact with process fluid and one side open to the atmosphere, either directly or through open piping.
Plug drill-out means the removal of a plug (or plugs) that was used to isolate different sections of the well.
Process controller means an automated instrument used for maintaining a process condition such as liquid level, pressure, delta-pressure and temperature.
Pressure release means the emission of materials resulting from system pressure being greater than set pressure of the pressure relief device.
Pressure vessel means a storage vessel that is used to store liquids or gases and is designed not to vent to the atmosphere as a result of compression of the vapor headspace in the pressure vessel during filling of the pressure vessel to its design capacity.
Pressurized mode means when the compressor contains natural gas that is maintained at a pressure higher than the atmospheric pressure.
Process improvement means routine changes made for safety and occupational health requirements, for energy savings, for better utility, for ease of maintenance and operation, for correction of design deficiencies, for bottleneck removal, for changing product requirements, or for environmental control.
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.
Process unit shutdown means a work practice or operational procedure that stops production from a process unit or part of a process unit during which it is technically feasible to clear process material from a process unit or part of a process unit consistent with safety constraints and during which repairs can be accomplished. The following are not considered process unit shutdowns:
(1) An unscheduled work practice or operational procedure that stops production from a process unit or part of a process unit for less than 24 hours.
(2) An unscheduled work practice or operational procedure that would stop production from a process unit or part of a process unit for a shorter period of time than would be required to clear the process unit or part of the process unit of materials and start up the unit, and would result in greater emissions than delay of repair of leaking components until the next scheduled process unit shutdown.
(3) The use of spare equipment and technically feasible bypassing of equipment without stopping production.
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.
Qualified Professional Engineer means an individual who is licensed by a state as a Professional Engineer to practice one or more disciplines of engineering and who is qualified by education, technical knowledge, and experience to make the specific technical certifications required under this subpart. Professional engineers making these certifications must be currently licensed in at least one state in which the certifying official is located.
Quarter means a 3-month period. For purposes of standards for process unit equipment affected facilities at onshore natural gas processing plants, the first quarter concludes on the last day of the last full month during the 180 days following initial startup.
Reciprocating compressor means a piece of equipment that increases the pressure of a process gas by positive displacement, employing linear movement of the driveshaft.
Reciprocating compressor rod packing means a series of flexible rings in machined metal cups that fit around the reciprocating compressor piston rod to create a seal limiting the amount of compressed natural gas that escapes to the atmosphere, or other mechanism that provides the same function.
Recovered gas means gas recovered through the separation process during flowback.
Recovered liquids means any crude oil, condensate or produced water recovered through the separation process during flowback.
Reduced emissions completion means a well completion following fracturing or refracturing where gas flowback that is otherwise vented is captured, cleaned, and routed to the gas flow line or collection system, re-injected into the well or another well, used as an onsite fuel source, or used for other useful purpose that a purchased fuel or raw material would serve, with no direct release to the atmosphere.
Reduced sulfur compounds means 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 accordance with § 60.5395b(c)(1).
Repaired means the following:
(1) For the purposes of fugitive emissions components affected facilities, that fugitive emissions components are adjusted, replaced, or otherwise altered, in order to eliminate fugitive emissions and resurveyed as specified in § 60.5397b(h)(4) and it is verified that emissions from the fugitive emissions components are below the applicable fugitive emissions definition.
(2) For the purposes of process unit equipment affected facilities, that equipment is adjusted, or otherwise altered, in order to eliminate a leak as defined in §§ 60.5400b and 60.5401b and is re-monitored as specified in § 60.5400b(b) introductory text and (b)(1) or § 60.5403b, respectively, to verify that emissions from the equipment are below the applicable leak definition. Pumps in light liquid service subject to § 60.5400b(c)(2) or § 60.5401b(b)(1)(ii) are not subject to re-monitoring.
Replacement cost means the capital needed to purchase all the depreciable components in a facility.
Returned to service means that a 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 storage vessel affected facility; or
(2) Installed in any location covered by this subpart and introduced with crude oil, condensate, intermediate hydrocarbon liquids or produced water.
Routed to a process or route to a process means the emissions are conveyed via a closed vent system to any enclosed portion of a process that is operational where the emissions are predominantly recycled and/or consumed in the same manner as a material that fulfills the same function in the process and/or transformed by chemical reaction into materials that are not regulated materials and/or incorporated into a product; and/or recovered.
Salable quality gas means natural gas that meets the flow line or collection system operator specifications, regardless of whether such gas is sold.
Screenout means an attempt to clear proppant from the wellbore to dislodge the proppant out of the well.
Self-contained process controller means a natural gas-driven process controller that releases gas into the downstream piping and not to the atmosphere, resulting in zero methane and VOC emissions.
Self-contained wet seal centrifugal compressor means:
(1) A wet seal centrifugal compressor system that is a closed process that ports the degassing emissions into the natural gas line at the compressor suction ( i.e., degassed emissions are recovered) or which has an intermediate closed process that degasses most of the gas entrained in the seal oil and sends that gas to another process. The de-gas emissions are routed back to suction or process directly from the closed or intermediate closed degassing process; after the closed or intermediate closed degassing process the oil is ultimately recycled for recirculation in the seals to the lube oil tank where any small amount of residual gas is released through a vent.
(2) A wet seal centrifugal compressor equipped with mechanical wet seals, where
(i) A differential pressure is maintained on the system and there is no off gassing of the lube oil, and
(ii) The mechanical seal is integrated into the compressor housing.
Sensor means a device that measures a physical quantity or the change in a physical quantity such as temperature, pressure, flow rate, pH, or liquid level.
Separation flowback stage means the period during a well completion operation when it is technically feasible for a separator to function. The separation flowback stage ends either at the startup of production, or when the well is shut in and permanently disconnected from the flowback equipment.
Separator dump valve means, for purposes of the fugitive emission standards in §§ 60.5397b and 60.5398b, a liquid-control valve in a separator that controls the liquid level within the separator vessel.
Single wellhead only well site means a wellhead only well site that contains only one wellhead and no major production and processing equipment.
Small well site means, for purposes of the fugitive emissions standards in §§ 60.5397b and 60.5398b, a well site that contains a single wellhead, no more than one piece of certain major production and processing equipment, and associated meters and yard piping. Small well sites cannot include any controlled storage vessels (or controlled tank batteries), control devices, natural gas-driven process controllers, or natural gas-driven pumps.
Startup of production means the beginning of initial flow following the end of flowback when there is continuous recovery of salable quality gas and separation and recovery of any crude oil, condensate, or produced water, except as otherwise provided in this definition. For the purposes of the fugitive monitoring requirements of § 60.5397b, startup of production means the beginning of the continuous recovery of salable quality gas and separation and recovery of any crude oil, condensate, or produced water.
Storage vessel means a tank or other vessel that contains an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water, and that is constructed primarily of nonearthen materials (such as wood, concrete, steel, fiberglass, or plastic) which provide structural support. A well completion vessel that receives recovered liquids from a well after startup of production following flowback for a period which exceeds 60 days is considered a storage vessel under this subpart. A tank or other vessel shall not be considered a storage vessel if it has been removed from service in accordance with the requirements of § 60.5395b(c)(1) until such time as such tank or other vessel has been returned to service. For the purposes of this subpart, the following are not considered storage vessels:
(1) Vessels that are skid-mounted or permanently attached to something that is mobile (such as trucks, railcars, barges or ships), and are intended to be located at a site for less than 180 consecutive days. If you do not keep or are not able to produce records, as required by § 60.5420b(c)(7)(v), showing that the vessel has been located at a site for less than 180 consecutive days, the vessel described herein is considered to be a storage vessel from the date the original vessel was first located at the site. This exclusion does not apply to a well completion vessel as described above.
(2) Process vessels such as surge control vessels, bottoms receivers or knockout vessels.
(3) Pressure vessels designed to operate in excess of 204.9 kilopascals and without emissions to the atmosphere.
Sulfur production rate means the rate of liquid sulfur accumulation from the sulfur recovery unit.
Sulfur recovery unit means a process device that recovers element sulfur from acid gas.
Surface site means any combination of one or more graded pad sites, gravel pad sites, foundations, platforms, or the immediate physical location upon which equipment is physically affixed.
Sweetening unit means a process device that removes hydrogen sulfide and/or carbon dioxide from the sour natural gas stream.
Tank battery means a group of all storage vessels that are manifolded together for liquid transfer. A tank battery may consist of a single storage vessel if only one storage vessel is present.
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-6 to this part.
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 be obtained if all reduced sulfur compounds were converted to SO 2 (ppmv or kg/dscm (lb/dscf)).
UIC Class I oilfield disposal well means a well with a UIC Class I permit that meets the definition in 40 CFR 144.6(a)(2) and receives eligible fluids from oil and natural gas exploration and production operations.
UIC Class II oilfield disposal well means a well with a UIC Class II permit where wastewater resulting from oil and natural gas production operations is injected into underground porous rock formations not productive of oil or gas, and sealed above and below by unbroken, impermeable strata.
Underground storage vessel means a storage vessel stored below ground.
Well means a hole drilled for the purpose of producing oil or natural gas, or a well into which fluids are injected.
Well completion means the process that allows for the flowback of petroleum or natural gas from newly drilled wells to expel drilling and reservoir fluids and tests the reservoir flow characteristics, which may vent produced hydrocarbons to the atmosphere via an open pit or tank.
Well completion operation means any well completion with hydraulic fracturing or refracturing occurring at a well completion affected facility.
Well completion vessel means a vessel that contains flowback during a well completion operation following hydraulic fracturing or refracturing. A well completion vessel may be a lined earthen pit, a tank or other vessel that is skid-mounted or portable. A well completion vessel that receives recovered liquids from a well after startup of production following flowback for a period which exceeds 60 days is considered a storage vessel under this subpart.
Well site means one or more surface sites that are constructed for the drilling and subsequent operation of any oil well, natural gas well, or injection well. For the purposes of the fugitive emissions standards at § 60.5397b, a well site does not include:
(1) UIC Class II oilfield disposal wells and disposal facilities;
(2) UIC Class I oilfield disposal wells; and
(3) The flange immediately upstream of the custody meter assembly and equipment, including fugitive emissions components, located downstream of this flange.
Wellhead means the piping, casing, tubing and connected valves protruding above the earth's surface for an oil and/or natural gas well. The wellhead ends where the flow line connects to a wellhead valve. The wellhead does not include other equipment at the well site except for any conveyance through which gas is vented to the atmosphere.
Wellhead only well site means, for the purposes of the fugitive emissions standards at § 60.5397b and the standards in § 60.5398b, a well site that contains one or more wellheads and no major production and processing equipment.
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.
Yard piping means hard-piping at a well site, centralized production facility, or compressor station that is not part of a closed vent system.
§ 60.5432b   How do I determine whether a well is a low pressure well using the low pressure well equation?
(a) To determine that your well is a low pressure well subject to § 60.5375b(f), you must determine whether the characteristics of the well are such that the well meets the definition of low pressure well in § 60.5430b. To determine that the well meets the definition of low pressure well in § 60.5430b, you must use the low pressure well equation:
(b) You must determine the four values in paragraphs (a)(4) through (7) of this section, using the calculations in paragraphs (b)(1) through (15) of this section.
(1) Determine the value of the bottom hole pressure, P BH ( psia ), based on available information at the well site, or by calculating it using the reservoir pressure, P R ( psia ), in the following equation:
(2) Determine the value of the bottom hole temperature, T BH ( F ), based on available information at the well site, or by calculating it using the true vertical depth of the well, L (ft), in the following equation:
(3) Calculate the value of the applicable natural gas specific gravity that would result from a separator pressure of 100 psig, γ gs , using the following equation with: Separator at standard conditions (pressure, p = 14.7 ( psia ), temperature, T = 60 ( F )); the oil API gravity at the well site, γ 0 ; and the gas specific gravity at the separator under standard conditions, γ gp = 0.75:
(4) Calculate the value of the applicable dissolved GOR, Rs (scf/STBO), using the following equation with: The bottom hole pressure, P BH ( psia ), determined in (b)(1) of this section; the bottom hole temperature, T BH ( F ), determined in (b)(2) of this section; the gas gravity at separator pressure of 100 psig, γ gs , calculated in (b)(3) of this section; the oil API gravity, γ o , at the well site; and the constants, C1, C2, and C3, found in Table 1 to this paragraph(b)(4):
Table 1 to Paragraph ( b )(4)—Coefficients for the Correlation for R s
(5) Calculate the value of the oil formation volume factor, Bo (bbl/STBO), using the following equation with: The bottom hole temperature, T BH ( F ), determined in paragraph (b)(2) of this section; the gas gravity at separator pressure of 100 psig, γ gs , calculated in paragraph (b)(3) of this section; the dissolved GOR, Rs (scf/STBO), calculated in paragraph (b)(4) of this section; the oil API gravity, γ o, at the well site; and the constants, C1, C2, and C3, found in Table 2 to this paragraph (b)(5):
Table 2 to Paragraph ( b )(5)—Coefficients for the Correlation for B o
(6) Calculate the density of oil at the wellhead,
(7) Calculate the density of oil at bottom hole conditions,
(8) Calculate the density of oil in the well,
(9) Calculate the oil flow rate, q o ( cu ft/sec, ) using the following equation with: the oil formation volume factor, Bo (bbl/STBO), as calculated in paragraph (b)(5) of this section; and the estimated oil production rate at the well head, Qo (STBO/day):
(10) Calculate the critical pressure, P c (psia), and critical temperature, T c (R), using the equations below with: Gas gravity at standard conditions (pressure, P = 14.7 ( psia ), temperature, T = 60 ( F )), γ = 0.75; and where the mole fractions of nitrogen, carbon dioxide and hydrogen sulfide in the gas are X N 2 = 0.168225, X CO 2 = 0.013163, and X H 2 S = 0.013680, respectively:
(11) Calculate reduced pressure, P r , and reduced temperature, T r , using the following equations with: the bottom hole pressure, P BH , as determined in paragraph (b)(1) of this section; the bottom hole temperature, T BH ( F ), as determined in paragraph (b)(2) of this section in the following equations:
(12)(i) Calculate the gas compressibility factor, Z , using the following equation with the reduced pressure, P r , calculated in paragraph (b)(11) of this section:
(ii) The values for A, B, C, D in the above equation, are calculated using the following equations with the reduced pressure, P r , and reduced temperature, T r , calculated in paragraph (b)(11) of this section:
(13) Calculate the gas formation volume factor,
(14) Calculate the gas flow rate,
(15) Calculate the flow rate of water in the well, q w ( cu ft/sec ), using the following equation with the water production rate Qw (bbl/day) at the well site:
§§ 60.5433b-60.5439b   [Reserved]
§ 60.5360c   What is the purpose of this subpart?
This subpart establishes emission guidelines and compliance schedules for the control of greenhouse gas (GHG) emissions from designated facilities in the crude oil and natural gas source category as defined in the Model Rule at § 60.5430c, in accordance with section 111(d) of the Clean Air Act and subpart Ba of this part. The designated facilities, standards section reference and compliance dates are listed in table 1 to this subpart. To the extent any requirement of this subpart is inconsistent with the requirements of subpart A or Ba of this part, the requirements of this subpart will apply.
§ 60.5361c   Which pollutants are regulated by this subpart?
(a) Scope. The pollutants regulated by this subpart are greenhouse gases (GHG). The greenhouse gas standards in this subpart are in the form of a limitation on emissions of methane from designated facilities in the crude oil and natural gas source category that commenced construction, modification, or reconstruction on or before December 6, 2022.
(b) PSD and title V Thresholds for Greenhouse Gases. (1) For the purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions from facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any State Implementation Plan (SIP) approved by the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48).
(2) For the purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from facilities regulated in the plan, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49).
(3) For the purposes of 40 CFR 70.2, with respect to GHG emissions from facilities regulated in the plan, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in 40 CFR 70.2.
(4) For the purposes of 40 CFR 71.2, with respect to GHG emissions from facilities regulated in the plan, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in 40 CFR 71.2 40 CFR.
§ 60.5362c   Am I affected by this subpart?
(a) If you are the Administrator of an air pollution control agency in a state or United States protectorate with one or more designated facilities that commenced construction, modification, or reconstruction on or before December 6, 2022, you must submit a state or Tribal plan to the U.S. Environmental Protection Agency (EPA) that implements the emission guidelines contained in this subpart. The submission of such plan shall be made in electronic format according to subpart Ba of this part.
(b) If you are the Administrator of an air pollution control agency in a state or United States protectorate with no designated facilities for which construction commenced on or before December 6, 2022, you must submit a negative declaration letter in place of the state or Tribal plan. The submission of such negative declaration letter shall be made in electronic format according to subpart Ba of this part.
(c) You must submit the state or Tribal plan or negative declaration letter to EPA by the date March 9, 2026.
§ 60.5363c   What must I include in my state or Tribal plan?
(a) You must include the ten items described in paragraphs (a)(1) through (10) of this section in your state or Tribal plan.
(1) Inventory of designated facilities. For purposes of this subpart, § 60.25a(a) does not apply.
(2) Inventory of emissions from designated facilities in your state. For purposes of this subpart, § 60.25a(a) does not apply.
(3) Compliance schedules for each designated facility or logical grouping of designated facilities.
(4) Standards of performance for designated facilities that are at least as stringent as the emission guidelines contained in this subpart, unless otherwise provided for under § 60.5365c. Standards for performance for designated facilities must apply at all times, including periods of startup, shutdown, and malfunction.
(5) Performance testing, monitoring, recordkeeping, and reporting requirements.
(6) Documentation of meaningful engagement on such plan or plan revisions as specified in § 60.23a(i).
(7) Certification that the required hearing on the state or Tribal plan was held, a list of witnesses and their organizational affiliations, if any, appearing at the hearing, and a brief written summary of each presentation or written submission as specified in § 60.23a(c) through (e).
(8) Provision for state progress reports to EPA.
(9) Identification of enforceable state mechanisms that you selected for implementing the emission guidelines of this subpart.
(10) Demonstration of your state's legal authority to carry out the Clean Air Act section 111(d) state or Tribal plan.
(b) Unless superseded by this subpart, you must follow the requirements of subpart Ba of this part (Adoption and Submittal of State Plans for Designated Facilities) in your state or Tribal plan.
§ 60.5364c   How do I apply to use my state standards as part of my state or Tribal plan submission?
In order for you to apply to use your state standards as part of your state or Tribal plan submission your state requirements for designated facilities must meet the standards of performance criteria specified in paragraph (a) of this section and you must provide the supporting documentation that you met those criteria as specified in paragraph (b) of this section.
(a) You must demonstrate that the state standards of performance established for a designated facility in your state or Tribal plan meet the equivalency criteria specified in paragraphs (a)(1) through (6) of this section when compared to the designated facility presumptive standards specified in EG OOOOc.
(1) Designated facility,
(2) Designated pollutant,
(3) Standard type/format of standard,
(4) Emission reductions (considering applicability thresholds and exemptions) unless relying on § 60.5365c,
(5) Compliance determination method, and
(6) Ongoing compliance assurance requirements ( e.g., monitoring, recordkeeping and reporting requirements).
(b) You must provide the supporting documentation that you met the equivalency criteria specified in paragraph (a) of this section as specified in paragraphs (b)(1) through (3) of this section.
(1) Your state or Tribal plan should identify the designated facility requirements of your state program that you are submitting for approval to become federally enforceable requirements under the plan.
(2) You must include a detailed explanation and analysis of how the relied upon state standards are at least as stringent as the requirements of the final EG based on each of the criteria specified in paragraph (a) of this section, or comply with § 60.5365c for paragraph (a)(4) of this section.
(3) You must include a copy of the actual state law/regulation or document submitted for approval and incorporation into the state or Tribal plan.
§ 60.5365c   How do I apply for a less stringent standard taking into consideration the remaining useful life of a designated facility and other factors?
You may apply a standard of performance to a designated facility that is less stringent than otherwise required by the emission guidelines, provided you meet the requirements specified in § 60.24a.
§ 60.5366c   [Reserved]
§ 60.5367c   Is there an approval process for my state or Tribal plan?
Yes. The EPA will review your state or Tribal plan according to § 60.27a.
(a) The EPA will determine the completeness of your plan submission according § 60.27a(g).
(b) The EPA will act on your plan submission according to § 60.27a.
§ 60.5368c   What if my state or Tribal plan is not approvable?
If you do not submit a state or Tribal plan (or a negative declaration letter) by March 9, 2026, or if EPA disapproves your state plan, EPA will develop a Federal plan according to § 60.27a(c) through (f) to implement the emission guidelines contained in this subpart.
§ 60.5369c   Is there an approval process for a negative declaration letter?
No. The EPA has no formal review process for negative declaration letters. Once your negative declaration letter has been received, the EPA will place a copy in the public docket and publish a notice in the Federal Register. If, at a later date, a designated facility for which construction commenced on or before December 6, 2022, is found in your state, that designated facility must be subject to a state, Tribal, or Federal plan in accordance with the requirements of this subpart and subpart Ba.
§ 60.5370c   What compliance schedule must I include in my state or Tribal plan?
(a) For designated facilities that commenced construction, modification or reconstruction on or before December 6, 2022, your state or Tribal plan must include compliance schedules that require designated facilities to achieve final compliance as expeditiously as practicable after approval of the state or Tribal plan but not later than the dates specified in § 60.5360c of this subpart, as applicable to each designated facility.
(b) The plan must include legally enforceable increments of progress to achieve compliance for each designated facility or category of facilities, as specified in §§ 60.5379c through 60.5381c.
§ 60.5371c   What requirements apply to revisions to my state or Tribal plan?
(a) Any significant revision to a state or Tribal plan shall be adopted and submitted as specified in § 60.28a.
(b) A revision of a plan, or any portion thereof, shall not be considered part of an applicable plan until approved by the Administrator in accordance with this subpart and subpart Ba of this part.
§ 60.5372c   In lieu of a state or Tribal plan submittal, are there other acceptable option(s) for a state to meet its Clean Air Act section 111(d) obligations?
Yes, a state may meet its Clean Air Act section 111(d) obligations by submitting an acceptable written request for delegation of an applicable Federal plan that meets the requirements of this section. This is the only other option for a state to meet its section 111(d) obligations.
(a) An acceptable Federal plan delegation request must include the following:
(1) A demonstration of adequate resources and legal authority to administer and enforce the Federal plan.
(2) The items under § 60.5363c(a)(1), (a)(2), and (a)(8) of this subpart.
(3) Certification that the hearing on the state delegation request, similar to the hearing for a state or Tribal plan submittal, was held, a list of witnesses and their organizational affiliations, if any, appearing at the hearing, and a brief written summary of each presentation or written submission.
(4) A commitment to enter into a Memorandum of Agreement with the Regional Administrator that sets forth the terms, conditions, and effective date of the delegation and that serves as the mechanism for the transfer of authority. Additional guidance and information is given in EPA's Delegation Manual, Item 7-139, Implementation and Enforcement of 111(d)(2) and 111(d)/(2)/129 (b)(3) Federal plans.
(b) A state with an already approved oil and natural gas designated facility Clean Air Act section 111(d) state or Tribal plan is not precluded from receiving the EPA's approval of a delegation request for any revised Federal plan, provided the requirements of paragraph (a) of this section are met, and at the time of the delegation request, the state also requests withdrawal of the EPA's previous state or Tribal plan approval.
(c) A state's Clean Air Act section 111(d) obligations are separate from its obligations under title V of the Clean Air Act.
§ 60.5373c   What authorities will not be delegated to state, local, or Tribal agencies?
The authorities that will not be delegated to state, local, or Tribal agencies are specified in paragraphs (a) through (h) of this section.
(a) Approval of alternatives to the emission limits and standards in tables 1, 2, and 3 to this subpart and operating limits established under § 60.5412c, § 60.5415c, or § 60.5417c.
(b) Approval of major alternatives to test methods.
(c) Approval of major alternatives to monitoring.
(d) Approval of major alternatives to recordkeeping and reporting.
(e) Approval of an alternative to any electronic reporting required by this subpart.
(f) [Reserved]
(g) [Reserved]
(h) Performance test and data reduction waivers under § 60.8(b).
§ 60.5374c   Does this subpart directly affect designated facility owners and operators in my state?
(a) No. This subpart does not directly affect designated facility owners and operators in your state. However, designated facility owners and operators must comply with the state or Tribal plan you develop to implement the emission guidelines contained in this subpart. States may choose to incorporate the model rule text directly in their state or Tribal plan.
(b) If you do not submit a plan to implement and enforce the guidelines contained in this subpart by the date 24 months after promulgation of this subpart, or if EPA disapproves your plan, the EPA will implement and enforce a Federal plan, as provided in § 60.5368c of this subpart, to ensure that each designated facility within your state that commenced construction, modification or reconstruction on or before December 6, 2022, reaches compliance with all the provisions of this subpart by the dates specified in § 60.5360c of this subpart.
§ 60.5375c   What designated facilities must I address in my state or Tribal plan?
(a) Your state or Tribal plan must address designated facilities that meet all three criteria described in paragraphs (a)(1) through (3) of this section.
(1) Designated facilities in your state that commenced construction, modification, or reconstruction on or before December 6, 2022.
(2) Designated facilities that are listed in table 1 to this subpart.
(3) Designated facilities not exempt under § 60.14(e).
(b) If the owner or operator of a designated facility makes changes that meet the definition of modification after December 6, 2022, the designated facility becomes subject to subpart OOOOb of this part, and the state or Tribal plan no longer applies to that facility.
(c) If the owner or operator of a designated facility makes physical or operational changes to a designated facility for which construction commenced on or before September 9, 2024, primarily to comply with your state or Tribal plan, subpart OOOOb of this part, does not apply to that designated facility. Such changes do not qualify as modifications under subpart OOOOb of this part.
§ 60.5376c   What is the “model rule” in this subpart?
(a) The model rule is the portion of these emission guidelines (§§ 60.5385c through 60.5430c of this subpart) that includes the presumptive standards for designated facilities as well as associated measures to assure compliance including monitoring, recordkeeping, and reporting. The model rule is organized in regulation format. You must develop a state or Tribal plan that is at least as protective as the model rule, or comply with § 60.5365c. You may use the model rule language as part of your state or Tribal plan. Alternative language may be used in your state or Tribal plan if you demonstrate that the alternative language is at least as protective as the model rule contained in this subpart, or comply with § 60.5365c.
(b) In the model rule of §§ 60.5385c through 60.5430c, “Administrator” has the meaning specified in § 60.2.
§ 60.5377c   How does the model rule relate to the required elements of my state or Tribal plan?
You may use the model rule to satisfy the state or Tribal plan requirements specified in § 60.5363c(a)(3) through (a)(5).
§ 60.5378c   What are the principal components of the model rule?
The model rule contains the nine major components listed in paragraphs (a) through (i) of this section.
(a) Increments of progress toward compliance.
(b) Operator training and qualification.
(c) Emission limits, emission standards, and operating limits.
(d) Initial compliance requirements.
(e) Continuous compliance requirements.
(f) Performance testing, monitoring, and calibration requirements.
(g) Recordkeeping and reporting.
(h) Definitions.
(i) Tables.
§ 60.5379c   What are my requirements for meeting increments of progress and achieving final compliance?
You must meet one increment of progress as specified in paragraph (a) of this section and you must submit the Notification of Compliance report as specified in paragraph (b) of this section.
(a) Submit a final compliance control plan on or before 28 months after the state plan submittal deadline specified in § 60.5362c(c).
(b) Submit a Notification of Compliance report on or before 60 days after the state plan compliance date as specified in § 60.5420c.
§ 60.5380c   What if I do not meet the final control plan increment of progress compliance date?
If you fail to meet the final compliance control plan increment of progress report compliance date, you must submit a notification to the Administrator postmarked within 10 business days after the required submittal date for that increment of progress. You must inform the Administrator that you did not meet the increment, and you must continue to submit reports each subsequent calendar month until the increment of progress is met.
§ 60.5381c   How do I comply with the increment of progress for submittal of a final compliance control plan?
For your final compliance control plan increment of progress report, you must satisfy the requirements specified in paragraphs (a) through (c) of this section.
(a) Your final control plan must include the information specified paragraphs (a)(1) and (2) of this section.
(1) A description of the designated facilities covered under your plan.
(2) The emissions control methods that you plan to implement for each designated facility covered under your plan.
(b) A company is allowed to submit one plan that covers all of the company's designated facilities in a state in lieu of submitting a plan for each designated facility.
(c) Maintain an onsite copy of the final control plan.
§ 60.5385c   What is the purpose of this subpart?
(a) Scope. This subpart establishes emission standards and compliance schedules for the control of the pollutant greenhouse gases (GHG). The greenhouse gas standard in this subpart is in the form of a limitation on emissions of methane from designated facilities in the crude oil and natural gas source category that commence construction, modification, or reconstruction on or before December 6, 2022.
(b) Prevention of Significant Deterioration (PSD) and title V thresholds for Greenhouse Gases. (1) For the purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions from designated facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any State Implementation Plan (SIP) approved by the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48).
(2) For the purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from designated facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered the pollutant that otherwise is subject to regulation under the Clean Air Act as defined in 40 CFR 52.21(b)(49).
(3) For the purposes of 40 CFR 70.2, with respect to GHG emissions from designated facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered the pollutant that otherwise is “subject to regulation” as defined in 40 CFR 70.2.
(4) For the purposes of 40 CFR 71.2, with respect to GHG emissions from designated facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered the pollutant that otherwise is “subject to regulation” as defined in 40 CFR 71.2.
(c) Exemption. You are exempt from the obligation to obtain a permit under 40 CFR part 70 or 40 CFR part 71, provided you are not otherwise required by law to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a). Notwithstanding the previous sentence, you must continue to comply with the provisions of this subpart.
§ 60.5386c   Am I subject to this subpart?
You are subject to the applicable provisions of this subpart if you are the owner or operator of one or more of the onshore designated facilities listed in paragraphs (a) through (h) of this section, that is located within the Crude Oil and Natural Gas source category, as defined in § 60.5430c, for which you commence construction, modification, or reconstruction on or before December 6, 2022. Facilities located inside and including the Local Distribution Company (LDC) custody transfer station are not subject to this subpart.
(a) Each well designated facility, which is a single well drilled for the purpose of producing oil or natural gas.
(b) Each centrifugal compressor designated facility, which is a single centrifugal compressor. A centrifugal compressor located at a well site is not a designated facility under this subpart. A centrifugal compressor located at a centralized production facility is a designated facility under this subpart.
(c) Each reciprocating compressor designated facility, which is a single reciprocating compressor. A reciprocating compressor located at a well site is not a designated facility under this subpart. A reciprocating compressor located at a centralized production facility is a designated facility under this subpart.
(d) Each process controller designated facility, which is the collection of natural gas-driven process controllers at a well site, centralized production facility, onshore natural gas processing plant, or a compressor station. Natural gas-driven process controllers that function as emergency shutdown devices and process controllers that are not driven by natural gas are exempt from the designated facility.
(e)(1) Each storage vessel designated facility, which is a tank battery that has the potential for methane emissions equal to or greater than 20 tpy as specified in paragraph (e)(2) of this section. A tank battery with the potential for methane emissions below 20 tpy is not a storage vessel designated facility provided the owner or operator keeps records of the potential for emissions calculation for the life of the storage vessel or until such time the tank battery becomes a storage vessel designated facility because the potential for methane emissions meets or exceeds 20 tpy.
(2) The potential for methane emissions must be calculated as the cumulative emissions from all storage vessels within the tank battery as specified by the applicable requirements in paragraphs (e)(2)(i) through (iii) of this section. The determination may take into account requirements under a legally and practicably enforceable limit in an operating permit or other requirement established under a Federal, state, local, or Tribal authority.
(i) For purposes of determining the applicability of a storage vessel tank battery as a designated facility, a legally and practicably enforceable limit must include the elements provided in paragraphs (e)(2)(i)(A) through (F) of this section.
(A) A quantitative production limit and quantitative operational limit(s) for the equipment, or quantitative operational limits for the equipment;
(B) An averaging time period for the production limit in (e)(2)(i)(A), if a production-based limit is used, that is equal to or less than 30 days;
(C) Established parametric limits for the production and/or operational limit(s) in paragraph (e)(2)(i)(A), and where a control device is used to achieve an operational limit, an initial compliance demonstration ( i.e., performance test) for the control device that establishes the parametric limits;
(D) Ongoing monitoring of the parametric limits in (e)(2)(i)(C) that demonstrates continuous compliance with the production and/or operational limit(s) in (e)(2)(i)(A);
(E) Recordkeeping by the owner or operator that demonstrates continuous compliance with the limit(s) in (e)(2)(i)(A) through (D); and
(F) Periodic reporting that demonstrates continuous compliance.
(ii) For each tank battery located at a well site or centralized production facility, you must determine the potential for methane emissions within 60 days after the effective date of the approved state or Tribal plan, except as provided in paragraph (e)(4)(iv) of this section. The potential for methane emissions must be calculated using a generally accepted model or calculation methodology that accounts for flashing, working, and breathing losses, based on the maximum average daily throughput to the tank battery determined for a 30-day period of production.
(iii) For each tank battery not located at a well site or centralized production facility, including each tank battery located at a compressor station or onshore natural gas processing plant, you must determine the potential for methane emissions within 60 days after the effective date of the approved state or Tribal plan, using either method described in paragraph (e)(2)(iii)(A) or (B) of this section.
(A) Determine the potential for methane emissions using a generally accepted model or calculation methodology that accounts for flashing, working, and breathing losses, and based on the throughput to the tank battery established in a legally and practicably enforceable limit in an operating permit or other requirement established under a Federal, state, local, or Tribal authority; or
(B) Determine the potential for methane emissions using a generally accepted model or calculation methodology that accounts for flashing, working and breathing losses, based on projected maximum average daily throughput. Maximum average daily throughput is determined using a generally accepted engineering model ( e.g., volumetric condensate rates from the tank battery based on the maximum gas throughput capacity of each producing facility) to project the maximum average daily throughput for the tank battery.
(3) A storage vessel designated facility that subsequently has its potential for methane emissions decrease to less than 20 tpy shall remain a designated facility under this subpart.
(4) For storage vessels not subject to a legally and practicably enforceable limit in an operating permit or other requirement established under Federal, state, local, or Tribal authority, any vapor from the storage vessel that is recovered and routed to a process through a vapor recovery unit designed and operated as specified in this section is not required to be included in the determination of potential for methane emissions for purposes of determining designated facility status, provided you comply with the requirements of paragraphs (e)(4)(i) through (iv) of this section.
(i) You meet the cover requirements specified in § 60.5411c(b).
(ii) You meet the closed vent system requirements specified in § 60.5411c(a)(2) through (4) and (c).
(iii) You must maintain records that document compliance with paragraphs (e)(4)(i) and (ii) of this section.
(iv) In the event of removal of apparatus that recovers and routes vapor to a process, or operation that is inconsistent with the conditions specified in paragraphs (e)(4)(i) and (ii) of this section, you must determine the storage vessel's potential for methane emissions according to this section within 30 days of such removal or operation.
(5) The requirements of this paragraph (e)(5) apply to each storage vessel designated facility immediately upon return to service. A storage vessel designated facility or portion of a storage vessel designated facility that is reconnected to the original source of liquids remains a storage vessel designated facility subject to the same requirements that applied before being removed from service. Any storage vessel that is used to replace a storage vessel designated facility or portion of a storage vessel designated facility, or used to expand a storage vessel designated facility assumes the designated facility status of the storage vessel designated facility being replaced or expanded.
(6) A storage vessel with a capacity greater than 100,000 gallons used to recycle water that has been passed through two stage separation is not a storage vessel designated facility.
(f) Each process unit equipment designated facility, which is the group of all equipment within a process unit at an onshore natural gas processing plant is a designated facility. Equipment associated with a compressor station, dehydration unit, sweetening unit, underground storage vessel, field gas gathering system, or liquefied natural gas unit is covered by §§ 60.5400c, 60.5401c, 60.5402c, 60.5421c, and 60.5422c 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 §§ 60.5400c, 60.5401c, 60.5402c, 60.5421c, and 60.5422c.
(g) Each pump designated facility, which is the collection of natural gas-driven diaphragm and piston pumps at a well site, centralized production facility, onshore natural gas processing plant, or a compressor station. Pumps that are not driven by natural gas and that are not in operation 90 days or more per calendar year are not included in the pump designated facility.
(h) Each fugitive emissions components designated facility, which is the collection of fugitive emissions components at a well site, centralized production facility, or a compressor station.
§ 60.5387c   When must I comply with this subpart?
Table 1 of this subpart specifies the final compliance date.
§ 60.5388c   What standards apply to super-emitter events?
This section applies to super-emitter events. For purposes of this section, a super-emitter event is defined as any emissions event that is located at an oil and natural gas facility ( e.g., individual well site, centralized production facility, natural gas processing plant, or compressor station) and that is detected using remote detection methods and has a quantified emission rate of 100 kg/hr of methane or greater. Upon receiving a notification of a super emitter event issued by the EPA under § 60.5371b(c) in subpart OOOOb of this part, owners or operators must take the actions listed in paragraphs (a) and (b) of this section. Within 5 calendar days of receiving a notification from the EPA of a super-emitter event, the owner or operator of an oil and natural gas facility ( e.g., a well site, centralized production facility, natural gas processing plant, or compressor station) must initiate a super-emitter event investigation.
(a) Identification of super-emitter events. (1) If you do not own or operate an oil and natural gas facility within 50 meters from the latitude and longitude provided in the notification subject to the regulation under this subpart, report this result to the EPA under paragraph (b) of this section. Your super-emitter event investigation is deemed complete under this subpart.
(2) If you own or operate an oil and natural gas facility within 50 meters from the latitude and longitude provided in the notification, and there is a designated facility or associated equipment subject to this subpart onsite, you must investigate to determine the source of the super-emitter event in accordance with this paragraph (a) and report the results in accordance with paragraph (b) of this section. The investigation required by this paragraph (a)(2) of this section may include but is not limited to the actions specified below in paragraphs (a)(2)(i) through (v) of this section.
(i) Review any maintenance activities ( e.g., liquids unloading) or process activities from the designated facilities subject to regulation under this subpart, starting from the date of detection of the super-emitter event as identified in the notification, until the date of investigation, to determine if the activities indicate any potential source(s) of the super-emitter event emissions.
(ii) Review all monitoring data from control devices ( e.g., flares) from the designated facilities subject to regulation under this subpart from the initial date of detection of the super-emitter event as identified in the notification, until the date of receiving the notification from the EPA to identify malfunctions of control devices or periods when the control devices were not in compliance with applicable requirements and that indicate a potential source of the super-emitter event emissions.
(iii) If you conducted a fugitive emissions survey or periodic screening event in accordance with § 60.5397c or § 60.5398c(b) between the initial date of detection of the super-emitter event as identified in the notification and the date the notification from the EPA was received, review the results of the survey to identify any potential source(s) of the super-emitter event emissions.
(iv) If you use conduct continuous monitoring with advanced methane detection technology in accordance with § 60.5398c(c), review the monitoring data collected on or after the initial date of detection of the super-emitter event as identified in the notification, until the date of receiving the notification from the EPA.
(v) Screen the entire well site, centralized production facility, or compressor station with OGI, Method 21 of appendix A-7 to this part, or an alternative test method(s) approved per § 60.5398c(d), to determine if a super-emitter event is present
(3) If the source of the super-emitter event was found to be from fugitive emission components at a well site, centralized production facility, or compressor station subject to this subpart, you must comply with the repair requirements under § 60.5397c and the associated recordkeeping and reporting requirements under § 60.5420c(b)(8) and § 60.5420c(c)(13).
(b) Super-emitter event report. You must submit the results of the super-emitter event investigation conducted under paragraph (a) of this section to the EPA in accordance with paragraph (b)(1) of this section. If the super-emitter event ( i.e., emission at 100 kg/hr of methane or more) is ongoing at the time of the initial report, submit the additional information in accordance with paragraph (b)(2) of this section. You must attest to the information included in the report as specified in paragraph (b)(3) of this section.
(1) Within 15 days of receiving a notification from the EPA under § 60.5371b(c), you must submit a report of the super-emitter event investigation conducted under paragraph (a) of this section through the Super-Emitter Program Portal, at www.epa.gov/super-emitter. You must include the applicable information in paragraphs (b)(1)(i) through (viii) of this section in the report. If you have identified a demonstrable error in the notification, the report may include a statement of the demonstrable error.
(i) Notification Report ID of the super-emitter event notification.
(ii) Identification of whether you are the owner or operator of an oil and natural gas facility that is located within 50 meters from the latitude and longitude provided in the EPA notification. If you do not own or operate an oil and natural gas facility within 50 meters from the latitude and longitude provided in the EPA notification, you are not required to report the information in paragraphs (b)(1)(iii) through (viii) of this section.
(iii) General identification information for the facility, including, facility name, the physical address, applicable ID Number ( e.g., EPA ID Number, API Well ID Number), the owner or operator or responsible official (where applicable) and their email address.
(iv) Identification of whether there is a designated facility or associated equipment subject to regulation under this subpart at this oil and natural gas facility.
(v) Indication of whether you were able to identify the source of the super-emitter event. If you indicate you were unable to identify the source of the super-emitter event, you must certify that all applicable investigations specified in paragraphs (a)(2)(i) through (v) of this section have been conducted for all designated facilities and associated equipment subject to regulation under this subpart that are at this oil and natural gas facility, and you have determined that the designated facilities and associated equipment are not the source of the super-emitter event. If you indicate that you were not able to identify the source of the super-emitter event, you are not required to report the information in paragraphs (b)(1)(vi) through (viii) of this section.
(vi) The source(s) of the super-emitter event.
(vii) Identification of whether the source of the super-emitter event is a designated facility or associated equipment subject to regulation under of this subpart. If the source of the super-emitter event is a designated facility or associated equipment subject to regulation under this subpart, identify the applicable regulation(s) under this subpart.
(viii) Indication of whether the super-emitter event is ongoing at the time of the initial report submittal ( i.e., emission at 100 kg/hr of methane or more).
(A) If the super-emitter event is not ongoing at the time of the initial report submittal, provide the actual (or if not known, estimated) date and time the super-emitter event ended.
(B) If the super-emitter event is ongoing at the time of the initial report submittal, provide a short narrative of your plan to end the super-emitter event, including the targeted end date for the efforts to be completed and the super-emitter event ended.
(2) If the super-emitter event is ongoing at the time of the initial report submittal, within 5 business days of the date the super-emitter event ends you must update your initial report through the Super-Emitter Program Portal to provide the end date and time of the super-emitter event.
(3) You must sign the following attestation when submitting data into the Super-Emitter Program Portal: “I certify that the information provided in this report regarding the specified super-emitter event was prepared under my direction or supervision. I further certify that the investigations were conducted, and this report was prepared pursuant to the requirements of § 60.5371c (a) and (b). Based on my professional knowledge and experience, and inquiry of personnel involved in the assessment, the certification submitted herein is true, accurate, and complete. I am aware that knowingly false statements may be punishable by fine or imprisonment.”
§ 60.5390c   What GHG standards apply to gas well liquids unloading operations at well designated facilities?
(a) General requirements. You must comply with the requirements of this section for each gas well liquids unloading operation at your gas well designated facility as specified by paragraphs (a)(1) and (2) of this section. You have a general duty to safely maximize resource recovery and minimize releases to the atmosphere during gas well liquids unloading operations.
(1) If a gas well liquids unloading operation technology or technique employed does not result in venting of methane emissions to the atmosphere, you must comply with the requirements specified in paragraphs (a)(1)(i) and (ii) and (d) and (e) of this section. If an unplanned venting event occurs, you must meet the requirements specified in paragraphs (c) through (f) of this section.
(i) Comply with the recordkeeping requirements specified in § 60.5420c(c)(1)(i).
(ii) Submit the information specified in § 60.5420c(b)(1) and (2)(i) in the annual report.
(2) If a gas well liquids unloading operation technology or technique vents methane emissions to the atmosphere, you must comply with the requirements specified in paragraphs (b) and (c), or paragraph (g) of this section.
(b) Work Practice Standards. If a gas well liquids unloading operation employs a technology or technique that vents methane emissions to the atmosphere, you must comply with the requirements in paragraphs (b)(1) through (3) and paragraphs (c) through (f) of this section.
(1) Employ best management practices to minimize venting of methane emissions as specified in paragraph (c) of this section for each gas well liquids unloading operation.
(2) Comply with the recordkeeping requirements specified in § 60.5420c(c)(1)(ii).
(3) Submit the information specified in § 60.5420c(b)(1) and (2)(ii) in the annual report.
(c) Best management practice requirements. For each gas well liquids unloading operation complying with paragraphs (a)(2) and (b) of this section, you must develop, maintain, and follow a best management practice plan to minimize venting of methane emissions to the maximum extent possible from each gas well liquids unloading operation. This best management practice plan must meet the minimum criteria specified in paragraphs (c)(1) through (4) of this section.
(1) Include steps that create a differential pressure to minimize the need to vent a well to unload liquids,
(2) Include steps to reduce wellbore pressure as much as possible prior to opening the well to the atmosphere,
(3) Unload liquids through the separator where feasible, and
(4) Close all wellhead vents to the atmosphere and return the well to production as soon as practicable.
(d) Initial compliance. You must demonstrate initial compliance with the standards that apply to well liquids unloading operations at your well designated facilities as required by § 60.5410c(a).
(e) Continuous compliance. You must demonstrate continuous compliance with the standards that apply to well liquids unloading operations at your well designated facilities as required by § 60.5415c(a).
(f) Recordkeeping and recording. You must perform the required notification, recordkeeping and reporting requirements as specified in § 60.5420c(b)(2) and (c)(1).
(g) Other compliance options. Reduce methane emissions from well designated facilities gas wells that unload liquids by 95.0 percent by complying with the requirements specified in paragraphs (g)(1) and (2) of this section and meeting the initial and continuous compliance and recordkeeping and reporting requirements specified in paragraphs (g)(3) through (5) of this section.
(1) You must route emissions through a closed vent system to a control device that meets the conditions specified in § 60.5412c.
(2) You must route emissions through a closed vent system that meets the requirements of § 60.5411c(a) and (c).
(3) You must demonstrate initial compliance with standards that apply to well designated facility gas well liquids unloading as required by § 60.5410c(b).
(4) You must demonstrate continuous compliance with standards that apply to well designated facility gas well liquids unloading as required by § 60.5415c(b).
(5) You must perform the reporting as required by § 60.5420c(b)(1), (2), and (10) through (12), as applicable; and the recordkeeping as required by § 60.5420c(c)(1), (7), and (9) through (12), as applicable.
§ 60.5391c   What GHG standards apply to associated gas wells at well designated facilities?
(a) You must comply with either paragraph (a)(1), (2), (3), or (4) of this section for each associated gas well, except as provided in paragraphs (b), (c), and (d) of this section. You must also comply with paragraphs (f), (g), and (h) of this section.
(1) Recover the associated gas from the separator and route the recovered gas into a gas gathering flow line or collection system to a sales line.
(2) Recover the associated gas from the separator and use the recovered gas as an onsite fuel source.
(3) Recover the associated gas from the separator and use the recovered gas for another useful purpose that a purchased fuel or raw material would serve.
(4) Recover the associated gas from the separator and reinject the recovered gas into the well or inject the recovered gas into another well.
(b) If you meet one of the conditions in paragraphs (b)(1) or (2) of this section, you may route the associated gas to a control device that reduces methane emissions by at least 95.0 percent instead of complying with paragraph (a) of this section. The associated gas must be routed through a closed vent system that meets the requirements of § 60.5411c(a) and (c) and the control device must meet the conditions specified in § 60.5412c(a), (b), and (c).
(1) If the annual methane contained in the associated gas from your oil well is 40 tons per year or less at the initial compliance date, determined in accordance with paragraph (e) of this section.
(2) If you demonstrate and certify that it is not feasible to comply with paragraph (a)(1), (2), (3), and (4) of this section due to technical reasons by providing a detailed analysis documenting and certifying the technical reasons for this infeasibility in accordance with paragraphs (b)(2)(i) through (iv) of this section.
(i) In order to demonstrate that it is not feasible to comply with paragraph (a)(1), (2), (3), and (4) of this section, you must provide a detailed analysis documenting and certifying the technical reasons for this infeasibility. The demonstration must address the technical infeasibility for all options identified in (a)(1), (2), (3), and (4) of this section. Documentation of these demonstrations must be maintained in accordance with § 60.5420c(c)(2)(iv).
(ii) This demonstration must be certified by a professional engineer or another qualified individual with expertise in the uses of associated gas. The following certification, signed and dated by the qualified professional engineer or other qualified individual shall state: “I certify that the assessment of technical and safety infeasibility was prepared under my direction or supervision. I further certify that the assessment was conducted, and this report was prepared pursuant to the requirements of § 60.5391c(b)(2). Based on my professional knowledge and experience, and inquiry of personnel involved in the assessment, the certification submitted herein is true, accurate, and complete.”
(iii) This demonstration and certification are valid for no more than 12 months. You must re-analyze the feasibility of complying with paragraphs (a)(1), (2), (3), and (4) of this section and finalize a new demonstration and certification each year.
(iv) Documentation of these demonstrations, along with the certifications, must be maintained in accordance with § 60.5420c(c)(2)(iv) and submitted in annual reports in accordance with § 60.5420c(b)(3).
(c) If you are complying with paragraph (a) of this section, you may temporarily route the associated gas to a flare or control device in the situations and for the durations identified in paragraphs (c)(1), (2), (3), or (4) of this section. The associated gas must be routed through a closed vent system that meets the requirements of § 60.5411c(a) and (c) and the control device must meet the conditions specified in § 60.5412c. If you are routing to a flare, you must demonstrate that the § 60.18 flare requirements are met during the period when the associated gas is routed to the flare. Records must be kept of all temporary flaring instances in accordance with § 60.5420c(c)(2) and reported in the annual report in accordance with § 60.5420c(b)(3).
(1) For equal to or less than 24 hours during a deviation caused by malfunction causing the need to flare.
(2) For equal to or less than 24 hours during repair, maintenance including blow downs, a bradenhead test, a packer leakage test, a production test, or commissioning.
(3) For wells complying with paragraph (a)(1) of this section, for the duration of a temporary interruption in service from the gathering or pipeline system, or 30 days, whichever is less.
(4) For 72 hours from the time that the associated gas does not meet pipeline specifications, or until the associated gas meets pipeline specifications, whichever is less.
(d) If you are complying with paragraph (a), (b), or (c) of this section, you may vent the associated gas in the situations and for the durations identified in paragraphs (d)(1), (2), or (3) of this section. Records must be kept of all venting instances in accordance with § 60.5420c(c)(2) and reported in the annual report in accordance with § 60.5420c(b)(3).
(1) For up to 12 hours to protect the safety of personnel.
(2) For up to 30 minutes during bradenhead monitoring.
(3) For up to 30 minutes during a packer leakage test.
(e) Calculate the methane content in associated gas as specified in paragraph (e)(1) of this section and comply with paragraphs (e)(2) and (e)(3) of this section.
(1) Calculate the methane content in associated gas from your oil well using the following equation
(2) You must maintain records of the calculation of the methane in associated gas from your oil well results in accordance with § 60.5420c(c)(2), and submit the information, as well as the background information, in the next annual report in accordance with § 60.5420c(b)(3).
(3) If a process change occurs that could increase the methane content in the associated gas, you must recalculate the methane content in accordance with paragraph (e)(1) of this section.
(f) You must demonstrate initial compliance with the standards that apply to associated gas wells at well designated facilities as required by § 60.5410c(b).
(g) You must demonstrate continuous compliance with the standards that apply to associated gas wells at well designated facilities as required by § 60.5415c(b).
(h) You must perform the recordkeeping and reporting as required by § 60.5420c(b)(1), (3), and (10) through (12), as applicable, and § 60.5420c(c)(2) and (7) and (9) through (12), as applicable.
§ 60.5392c   What GHG standards apply to centrifugal compressor designated facilities?
Each centrifugal compressor designated facility must comply with the GHG standards in paragraphs (a) through (d) of this section.
(a) Each centrifugal compressor designated facility that is a wet or dry seal centrifugal compressor must comply with the GHG standards, using volumetric flow rate as a surrogate, as specified in paragraphs (a)(1) and (2) of this section. Alternatively, you have the option of complying with the GHG standards for your wet seal and dry seal centrifugal compressor by meeting the requirements specified in paragraph (a)(3), and either paragraph (a)(4) or (5) of this section.
(1) If you utilize a centrifugal compressor, you must comply with the GHG standards in paragraph (a)(1)(i) through (iii) of this section, and the seal repair requirements of paragraph (a)(1)(iv) of this section.
(i) You must conduct volumetric flow rate measurements from each wet seal centrifugal compressor (including each self-contained wet seal centrifugal compressor) vent using the methods specified in paragraph (a)(2) of this section and in accordance with the schedule specified in paragraphs (a)(1)(i)(A) and (B) of this section. The volumetric flow rate, measured in accordance with paragraph (a)(2) of this section, must not exceed 3 standard cubic feet per minute (scfm) per seal. If the individual seals are manifolded to a single open-vented line, the volumetric flow rate must not exceed the sum of the individual seals multiplied by 3 scfm. If the volumetric flow rate exceeds 3 scfm multiplied by the number of seals connected to the vent, the seals connected to the measured vent must be repaired as provided in paragraph (a)(1)(iv) of this section.
(A) You must conduct your first volumetric flow rate measurement from your wet seal centrifugal compressor (including self-contained wet seal centrifugal compressors) vents on or before 8,760 hours of operation 36 months after the state plan submittal deadline (as specified in § 60.5362c(c)), or on or before 8,760 hours of operation after startup, whichever date is later.
(B) You must conduct subsequent volumetric flow rate measurements from your wet seal centrifugal compressor (including self-contained wet seal centrifugal compressor) vents on or before 8,760 hours of operation after the previous measurement.
(ii) You must conduct volumetric flow rate measurements from each Alaska North Slope centrifugal compressor equipped with sour seal oil separator and capture system using the methods specified in paragraph (a)(2) of this section and in accordance with the schedule specified in paragraphs (a)(1)(ii)(A) and (B) of this section. The volumetric flow rate, measured in accordance with paragraph (a)(2) of this section, must not exceed 9 standard cubic feet per minute (scfm) per seal. If the individual seals are manifolded to a single open-vented line, the volumetric flow rate must not exceed the sum of the individual seals multiplied by 9 scfm. If the volumetric flow rate exceeds 9 scfm multiplied by the number of seals connected to the vent, the seals connected to the measured vent must be repaired as provided in paragraph (a)(1)(iv) of this section.
(A) You must conduct your first volumetric flow rate measurement from your centrifugal compressor equipped with sour seal oil separator and capture system utilized in Alaska wet seal vent on or before 8,760 hours of operation 36 months after the state plan submittal deadline (as specified in § 60.5362c(c)), or on or before 8,760 hours of operation after startup, whichever date is later.
(B) You must conduct subsequent volumetric flow rate measurements from your centrifugal compressor wet seal vents on or before 8,760 hours of operation after the previous measurement.
(iii) You must conduct volumetric flow rate vent measurements from each centrifugal compressor equipped with dry seals using the methods specified in paragraph (a)(2) of this section and in accordance with the schedule specified in paragraphs (a)(1)(iii)(A) and (B) of this section. The volumetric flow rate, measured in accordance with paragraph (a)(2) of this section, must not exceed 10 standard cubic feet per minute (scfm) per seal. If the individual seals are manifolded to a single open-vented line, the volumetric flow rate must not exceed the sum of the individual seals multiplied by 10 scfm. If the volumetric flow rate exceeds 10 scfm multiplied by the number of seals connected to the vent, the seals connected to the measured vent must be repaired as provided in paragraph (a)(1)(iv) of this section.
(A) You must conduct your first volumetric flow rate vent measurement from your centrifugal compressor equipped with a dry seal on or before 8,760 hours of operation 36 months after the state plan submittal deadline (as specified in § 60.5362c(c)), or on or before 8,760 hours of operation after startup, whichever date is later.
(B) You must conduct subsequent volumetric flow rate vent measurements from your centrifugal compressor equipped with a dry seal on or before 8,760 hours of operation after the previous measurement.
(iv) The seal must be repaired within 90 calendar days after the date of the volumetric emissions measurement that exceeds the applicable required flow rate per seal. You must conduct follow-up volumetric flow rate measurements from seal vents using the methods specified in paragraph (a)(2) of this section within 15 days after the repair to document that the rate has been reduced to less than the applicable required flow rate per seal. If the individual seals are manifolded to a single open-ended line or vent, the volumetric flow rate must be reduced to less than the sum of the individual seals multiplied by the applicable required flow rate per seal specified in paragraph (a)(1)(i) through (iii) of this section, as applicable. Delay of repair will be allowed if the conditions in paragraphs (a)(1)(iv)(A) or (B) of this section are met.
(A) If the repair of the wet or dry seal is technically infeasible, would require a vent blowdown, a compressor station shutdown, or would be unsafe to repair during operation of the unit, the repair must be completed during the next scheduled compressor station shutdown for maintenance, after a scheduled vent blowdown, or within 2 years of the date of the volumetric emissions measurement that exceeds the applicable required flow rate per seal, whichever is earliest. A vent blowdown is the opening of one or more blowdown valves to depressurize major production and processing equipment, other than a storage vessel.
(B) If the repair requires replacement of the compressor seal or a part thereof, but the replacement seal or part cannot be acquired and installed within the repair timelines specified under this section due to the condition specified in paragraph (a)(1)(iv)(B)( 1 ) of this section, the repair must be completed in accordance with paragraph (a)(1)(iv)(B)( 2 ) of this section and documented in accordance with § 60.5420c(c)(3)(iii)(F) through (H).
( 1 ) Seal or part thereof supplies had been sufficiently stocked but are depleted at the time of the required repair.
( 2 ) The required replacement seal or part must be ordered no later than 10 calendar days after the centrifugal compressor is added to the delay of repair list due to parts unavailability. The repair must be completed as soon as practicable, but no later than 30 calendar days after receipt of the replacement seal or part, unless the repair requires a compressor station shutdown. If the repair requires a compressor station shutdown, the repair must be completed in accordance with the timeframe specified in paragraph (a)(1)(iv)(A) of this section.
(2) You must determine the volumetric flow rates from your centrifugal compressor dry or wet seal vents as specified in paragraph (a)(2)(i) or (ii) of this section.
(i) For each dry or wet seal centrifugal compressor in operating-mode or in standby-pressurized-mode, determine volumetric flow rate at standard conditions from each dry or wet seal vent using one of the methods specified in paragraphs (a)(2)(i)(A) through (C) of this section.
(A) You may choose to use any of the methods set forth in § 60.5405c(a) to screen for leaks/emissions. For the purposes of this paragraph, when using any of the methods in § 60.5405c(a), emissions are detected whenever a leak is detected according to the method. If emissions are detected using the methods set forth in § 60.5405c(a), then you must use one of the methods specified in paragraph (a)(2)(i)(B) or (C) of this section to determine the volumetric flow rate. If emissions are not detected using the methods in § 60.5405c(a), then you may assume that the volumetric flow rate is zero.
(B) Use a temporary or permanent flow meter according to methods set forth in § 60.5405c(b).
(C) Use a high-volume sampler according to the methods set forth in § 60.5405c(c).
(ii) For conducting measurements on manifolded groups of dry or wet seal centrifugal compressors, you must determine the volumetric flow rate from the compressor dry or wet seal as specified in paragraph (a)(2)(ii)(A) or (B) of this section.
(A) Measure at a single point in the manifold downstream of all dry or wet seal compressor inputs and, if practical, prior to comingling with other non-compressor emission sources.
(B) Determine the volumetric flow rate at standard conditions from the common stack using one of the methods specified in paragraph (a)(2)(i)(A) through (C) of this section.
(3) As an alternative to meeting the requirements of paragraphs (a)(1) and (2) of this section for compressors with wet seals and dry seals, you have the option of reducing methane emissions from each centrifugal compressor wet seal fluid degassing system by 95.0 percent by meeting the requirements of paragraph (a)(4) of this section, or the option of routing the emissions from each centrifugal compressor wet seal fluid degassing system or dry seal system to a process by meeting the requirements of paragraph (a)(5) of this section.
(4) If you use a control device to reduce methane emissions by 95.0 percent, you must equip the wet seal fluid degassing system with a cover that meets the requirements of § 60.5411c(b). The cover must be connected through a closed vent system that meets the requirements of § 60.5411c(a) and (c) and the closed vent system must be routed to a control device that meets the conditions specified in § 60.5412c.
(5) If you route the emissions to a process, you must equip the wet seal fluid degassing system or dry seal system with a cover that meets the requirements of § 60.5411c(b). The cover must be connected through a closed vent system that meets the requirements of § 60.5411c(a) and (c).
(b) You must demonstrate initial compliance with the standards that apply to centrifugal compressor designated facilities as required by § 60.5410c(c).
(c) You must demonstrate continuous compliance with the standards that apply to centrifugal compressor designated facilities as required by § 60.5415c(c).
(d) You must perform the reporting as required by § 60.5420c(b)(1) and (4) and (b)(10) through (12), as applicable; and the recordkeeping as required by § 60.5420c(c)(3) and (c)(7) through (12), as applicable.
§ 60.5393c   What GHG standards apply to reciprocating compressor designated facilities?
Each reciprocating compressor designated facility must comply with the GHG standards, using volumetric flow rate as a surrogate, in paragraphs (a) through (c) of this section, or the GHG standards in paragraph (d) of this section. You must also comply with the requirements in paragraphs (e) through (g) of this section.
(a) The volumetric flow rate of each cylinder, measured in accordance with paragraph (b) or (c) of this section, must not exceed 2 scfm per individual cylinder. If the individual cylinders are manifolded to a single open-ended vent line, the volumetric flow rate must not exceed the sum of the individual cylinders multiplied by 2 scfm. You must conduct measurements of the volumetric flow rate in accordance with the schedule specified in paragraphs (a)(1) and (2) of this section and determine the volumetric flow rate per cylinder in accordance with paragraph (b) or (c) of this section. If the volumetric flow rate, measured in accordance with paragraph (b) or (c) of this section, for a cylinder exceeds 2 scfm per cylinder (or a combined volumetric flow rate greater than the number of compression cylinders multiplied by 2 scfm), the rod packing or packings must be repaired or replaced as provided in paragraph (a)(3) of this section.
(1) You must conduct your first volumetric flow rate measurements from your reciprocating compressor rod packing vent on or before 8,760 hours of operation after the effective date of an approved state or Tribal plan, on or before 8,760 hours of operation after last rod packing replacement, or on or before 8,760 hours of operation after startup, whichever date is later.
(2) You must conduct subsequent volumetric flow rate measurements from your reciprocating compressor rod packing vent on or before 8,760 hours of operation after the previous measurement which demonstrates compliance with the applicable volumetric flow rate of 2 scfm per cylinder (or a combined cylinder volumetric flow rate greater than the number of compression cylinders multiplied by 2 scfm), or on or before 8,760 hours of operation after last rod packing replacement, whichever date is later.
(3) The rod packing must be repaired or replaced within 90 calendar days after the date of the volumetric emissions measurement that exceeded 2 scfm per cylinder. You must conduct follow-up volumetric flow rate measurements from compressor vents using the methods specified in paragraph (b) of this section within 15 days after the repair (or rod packing replacement) to document that the rate has been reduced to less than 2 scfm per cylinder. Delay of repair will be allowed if the conditions in paragraphs (a)(3)(i) or (ii) of this section are met.
(i) If the repair (or rod packing replacement) is technically infeasible, would require a vent blowdown, a compressor station shutdown, or would be unsafe to repair during operation of the unit, the repair (or rod packing replacement) must be completed during the next scheduled compressor station shutdown for maintenance, after a scheduled vent blowdown, or within 2 years of the date of the volumetric emissions measurement that exceeds the applicable required flow rate per cylinder, whichever is earliest. A vent blowdown is the opening of one or more blowdown valves to depressurize major production and processing equipment, other than a storage vessel.
(ii) If the repair requires replacement of the rod packing or a part, but the replacement cannot be acquired and installed within the repair timelines specified under this section due to the condition specified in paragraph (a)(3)(ii)(A) of this section, the repair must be completed in accordance with paragraph (a)(3)(ii)(B) of this section and documented in accordance with § 60.5420c(c)(4)(viii) through (x).
(A) Rod packing or part supplies had been sufficiently stocked but are depleted at the time of the required repair.
(B) The required rod packing or part replacement must be ordered no later than 10 calendar days after the reciprocating compressor is added to the delay of repair list due to parts unavailability. The repair must be completed as soon as practicable, but no later than 30 calendar days after receipt of the replacement rod packing or part, unless the repair requires a compressor station shutdown. If the repair requires a compressor station shutdown, the repair must be completed in accordance with the timeframe specified in paragraph (a)(3)(i) of this section.
(b) You must determine the volumetric flow rate per cylinder from your reciprocating compressor as specified in paragraph (b)(1) or (2) of this section.
(1) For reciprocating compressor rod packing equipped with an open-ended vent line on compressors in operating or standby pressurized mode, determine the volumetric flow rate of the rod packing using one of the methods specified in paragraphs (b)(1)(i) through (iii) of this section.
(i) Determine the volumetric flow rate at standard conditions from the open-ended vent line using a high-volume sampler according to methods set forth in § 60.5405c(c).
(ii) Determine the volumetric flow rate at standard conditions from the open-ended vent line using a temporary or permanent meter, according to methods set forth in § 60.5405c(b).
(iii) Any of the methods set forth in § 60.5405c(a) to screen for leaks and emissions. For the purposes of this paragraph, emissions are detected whenever a leak is detected according to any of the methods in § 60.5405c(a). If emissions are detected using the methods set forth in § 60.5405c(a), then you must use one of the methods specified in paragraph (b)(1)(i) and (ii) of this section to determine the volumetric flow rate per cylinder. If emissions are not detected using the methods in § 60.5405c(a), then you may assume that the volumetric flow rate is zero.
(2) For reciprocating compressor rod packing not equipped with an open-ended vent line on compressors in operating or standby pressurized mode, you must determine the volumetric flow rate of the rod packing using the methods specified in paragraphs (b)(2)(i) and (ii) of this section.
(i) You must use the methods described in § 60.5405c(a) to conduct leak detection of emissions from the rod packing case into an open distance piece, or, for compressors with a closed distance piece, you must conduct annual leak detection of emissions from the rod packing vent, distance piece vent, compressor crank case breather cap, or other vent emitting gas from the rod packing.
(ii) You must measure emissions found in paragraph (b)(2)(i) of this section using a meter or high-volume sampler according to methods set forth in § 60.5405c(b) or (c).
(c) For conducting measurements on manifolded groups of reciprocating compressor designated facilities, you must determine the volumetric flow rate from reciprocating compressor rod packing vent as specified in paragraph (c)(1) and (2) of this section.
(1) Measure at a single point in the manifold downstream of all compressor vent inputs and, if practical, prior to comingling with other non-compressor emission sources.
(2) Determine the volumetric flow rate per cylinder at standard conditions from the common stack using one of the methods specified in paragraph (c)(2)(i) through (iv) of this section.
(i) A temporary or permanent flow meter according to the methods set forth in § 60.5405c(b).
(ii) A high-volume sampler according to methods set forth § 60.5405c(c).
(iii) An alternative method, as set forth in § 60.5405c(d).
(iv) Any of the methods set forth in § 60.5405c(a) to screen for emissions. For the purposes of this paragraph, emissions are detected whenever a leak is detected when using any of the methods in § 60.5405c(a). If emissions are detected using the methods set forth in § 60.5405c(a), then you must use one of the methods specified in paragraph (c)(2)(i) through (iii) of this section to determine the volumetric flow rate per cylinder. If emissions are not detected using the methods in § 60.5405c(a), then you may assume that the volumetric flow rate is zero.
(d) As an alternative to complying with the GHG standards in paragraphs (a) through (c) of this section, owners or operators can meet the requirements specified in paragraph (d)(1), (2), or (3) of this section.
(1) Collect the methane emissions from your reciprocating compressor rod packing using a rod packing emissions collection system that is operated to route the rod packing emissions to a process. In order to comply with this option, you must equip the reciprocating compressor with a cover that meets the requirements of § 60.5411c(b). The cover must be connected through a closed vent system that meets the requirements of § 60.5411c(a) and (c).
(2) Reduce methane emissions from each rod packing emissions collection system by using a control device that reduces methane emissions by 95.0 percent. In order to comply with this option, you must equip the reciprocating compressor with a cover that meets the requirements of § 60.5411c(b). The cover must be connected through a closed vent system that meets the requirements of § 60.5411c(a) and (c) and the closed vent system must be routed to a control device that meets the conditions specified in § 60.5412c.
(3) As an alternative to conducting the required volumetric flow rate measurements under paragraph (a) of this section, an owner or operator can choose to comply by replacing the rod packing on or before 8,760 hours of operation after the effective date of the final rule, on or before 8,760 hours of operation after the previous flow rate measurement, or on or before 8,760 hours of operation after the date of the most recent compressor rod packing replacement, whichever date is later.
(e) You must demonstrate initial compliance with standards that apply to reciprocating compressor designated facilities as required by § 60.5410c(d).
(f) You must demonstrate continuous compliance with standards that apply to reciprocating compressor designated facilities as required by § 60.5415c(f).
(g) You must perform the reporting requirements as specified in § 60.5420c(b)(1) and (5) and (10) through (12), as applicable; and the recordkeeping requirements as specified in § 60.5420c(c)(4) and (7) through (12), as applicable.
§ 60.5394c   What GHG standards apply to process controller designated facilities?
Each process controller designated facility must comply with the GHG standards in this section.
(a) You must design and operate each process controller designated facility with zero methane emissions to the atmosphere, except as provided in paragraph (b) of this section.
(1) If you comply by routing the emissions to a process, emissions must be routed to a process through a closed vent system.
(2) If you comply by using a self-contained natural gas-driven process controller, you must design and operate each self-contained natural gas-driven process controller with no identifiable emissions, as demonstrated by § 60.5416c(b).
(b) For each process controller designated facility located at a site in Alaska that does not have access to electrical power, you may comply with either paragraphs (b)(1) and (2) of this section or with paragraph (b)(3) of this section, instead of complying with paragraph (a) of this section.
(1) With the exception of natural gas-driven continuous bleed controllers that meet the condition in paragraph (b)(1)(i) of this section and that comply with paragraph (b)(1)(ii) of this section, each natural gas-driven continuous bleed process controller in the process controller designated facility must have a bleed rate less than or equal to 6 standard cubic feet per hour (scfh).
(i) A natural gas-driven continuous bleed process controller with a bleed rate higher than 6 scfh may be used if the requirements of paragraph (b)(1)(ii) of this section are met.
(ii) You demonstrate that a natural gas-driven continuous bleed controller with a bleed rate higher than 6 scfh is required. The demonstration must be based on the specific functional need, including but not limited to response time, safety, or positive actuation.
(2) Each natural gas-driven intermittent vent process controller in the process controller designated facility must comply with the requirements in paragraphs (b)(2)(i) and (ii) of this section.
(i) Each natural gas-driven intermittent vent process controller must not emit to the atmosphere during idle periods.
(ii) You must monitor each natural gas-driven intermittent vent process controller to ensure that it is not emitting to the atmosphere during idle periods, as specified in paragraphs (b)(2)(ii)(A) through (C) of this section.
(A) Monitoring must be conducted at the same frequency as specified for fugitive emissions components designated facilities located at the same type of site, as specified in § 60.5397c(g).
(B) You must include the monitoring of each natural gas-driven intermittent vent process controller in the monitoring plan required in § 60.5397c(b).
(C) When monitoring identifies emissions to the atmosphere from a natural gas-driven intermittent vent controller during idle periods, you must take corrective action by repairing or replacing the natural gas-driven intermittent vent process controller within 5 calendar days of the date the emissions to the atmosphere were detected. After the repair or replacement of a natural gas-driven intermittent vent process controller, you must re-survey the natural gas-driven intermittent vent process controller within five days to verify that it is not venting emissions during idle periods.
(3) You must reduce methane emissions from all controllers in the process controller designated facility by 95.0 percent. You must route emissions to a control device through a closed vent system that meets the conditions specified in § 60.5412c.
(c) If you route process controller emissions to a process or a control device, you must route the process controller designated facility emissions through a closed vent system that meets the requirements of § 60.5411c(a) and (c).
(d) You must demonstrate initial compliance with standards that apply to process controller designated facilities as required by § 60.5410c(e).
(e) You must demonstrate continuous compliance with standards that apply to process controller designated facilities as required by § 60.5415c(g).
(f) You must perform the reporting as required by § 60.5420c(b)(1), (6) and (10) through (12), as applicable, and the recordkeeping as required by § 60.5420c(c)(5), (7), and (9) through (12), as applicable.
§ 60.5395c   What GHG standards apply to pump designated facilities?
Each pump designated facility, you must comply with the GHG standards in this section.
(a) For each pump designated facility meeting the criteria specified in paragraphs (a)(1) or (2) of this section, you must design and operate the pump designated facility with zero methane emissions to the atmosphere. If you comply by routing the pump designated facility emissions to a process, the emissions must be routed to the process through a closed vent system.
(1) The pump designated facility is located at a site that has access to electrical power.
(2) The pump designated facility is located at a site that does not have access to electrical power and also has three or more natural gas-driven diaphragm pumps.
(b)(1) For each pump designated facility located at a site that does not have access to electrical power and that also has fewer than three natural gas-driven diaphragm pumps, you must comply with paragraph (b)(2) or (3) of this section, except as provided in paragraphs (b)(4) through (8) of this section.
(2) Emissions from the pump designated facility must be routed through a closed vent system to a process if a vapor recovery unit is onsite.
(3) If a vapor recovery unit is not onsite, you must reduce methane emissions from the pump designated facility by 95.0 percent. You must route designated pump facility emissions through a closed vent system to a control device meeting the conditions specified in § 60.5412c.
(4) You are not required to install an emissions control device or a vapor recovery unit, if such a unit is necessary to enable emissions to be routed to a process, solely for the purpose of complying with the requirements of paragraphs (b)(2) or (3) of this section. If no control device capable of achieving a 95.0 percent emissions reduction and no vapor recovery unit is present on site, you must comply with paragraph (b)(5) or (6) of this section, as applicable. For the purposes of this section, boilers and process heaters are not considered to be control devices.
(5) If an emissions control device is on site but is unable to achieve a 95.0 percent emissions reduction, you must route the pump designated facility emissions through a closed vent system to that control device. You must certify that there is no vapor recovery unit on site and that there is no control device capable of achieving a 95.0 percent emissions reduction on site.
(6) If there is no vapor recovery unit on site and no emission control device is on site, you must certify that there is no vapor recovery unit or emissions control device on site. If you subsequently install a control device or vapor recovery unit, you must meet the requirements of paragraphs (b)(6)(i) and (ii) of this section.
(i) You must be in compliance with the requirements of paragraphs (b)(1) through (3) of this section, as applicable, within 30 days of startup of the control device or vapor recovery unit.
(ii) You must maintain the records in § 60.5420c(c)(14)(ii) and (v), as applicable. You are no longer required to maintain the records in § 60.5420c(c)(14)(v) certifying that there is no vapor recovery unit or control device on site.
(7) If an owner or operator complying with paragraph (b)(1) of this section determines, through an engineering assessment, that routing the pump designated facility emissions to a control device or to a process is technically infeasible, the requirements specified in paragraphs (b)(7)(i) through (iii) of this section must be met.
(i) The owner or operator must conduct the assessment of technical infeasibility in accordance with the criteria in paragraph (b)(7)(ii) of this section and have it certified by either a qualified professional engineer or an in-house engineer with expertise on the design and operation of the pump designated facility and the control device or processes at the site in accordance with paragraph (b)(7)(iii) of this section.
(ii) The assessment of technical infeasibility to route emissions from the pump designated facility to an existing control device or process must include, but is not limited to, safety considerations, distance from the control device or process, pressure losses and differentials in the closed vent system, and the ability of the control device or process to handle the pump designated facility emissions which are routed to them. The assessment of technical infeasibility must be prepared under the direction or supervision of the qualified professional engineer or in-house engineer who signs the certification in accordance with paragraph (b)(7)(iii) of this section.
(iii) The following certification, signed and dated by the qualified professional engineer or in-house engineer, must state: “I certify that the assessment of technical infeasibility was prepared under my direction or supervision. I further certify that the assessment was conducted and this report was prepared pursuant to the requirements of § 60.5395c(b)(7)(ii). Based on my professional knowledge and experience, and inquiry of personnel involved in the assessment, the certification submitted herein is true, accurate, and complete.”
(8) If the pump designated facility emissions are routed to a control device or process and the control device or process is subsequently removed from the location or is no longer available such that there is no option to route to a control device or process, you are no longer required to be in compliance with the requirements of paragraph (b)(2) or (3) of this section, and instead must comply with paragraph (b)(6) of this section.
(c) If you use a control device or route to a process to reduce emissions, you must route the pump designated facility emissions through a closed vent system that meets the requirements of § 60.5411c(a) and (c).
(d) You must demonstrate initial compliance with standards that apply to pump designated facilities as required by § 60.5410c(f).
(e) You must demonstrate continuous compliance with the standards that apply to pump designated facilities as required by § 60.5415c(d).
(f) You must perform the reporting as required by § 60.5420c(b)(1), (9), and (b)(10) through (12), as applicable, and the recordkeeping as required by § 60.5420c(c)(7), (c)(9) through (12), and (14), as applicable.
§ 60.5396c   What GHG standards apply to storage vessel designated facilities?
Each storage vessel designated facility must comply with the GHG standards in this section, except as provided in paragraph (e) of this section.
(a) General requirements. You must comply with the requirements of paragraphs (a)(1) and (2) of this section. After 12 consecutive months of compliance with paragraph (a)(2) of this section, you may continue to comply with paragraph (a)(2) of this section, or you may comply with paragraph (a)(3) of this section, if applicable. If you choose to meet the requirements of paragraph (a)(3) of this section, you are not required to comply with the requirements of paragraph (a)(2) of this section except as provided in paragraphs (a)(3)(i) and (ii) of this section.
(1) Determine the potential for methane emissions in accordance with § 60.5386c(e)(2).
(2) Reduce methane emissions by 95.0 percent.
(3) Maintain the uncontrolled actual methane emissions from the storage vessel designated facility at less than 14 tpy without considering control in accordance with paragraphs (a)(3)(i) and (ii) of this section. Prior to using the uncontrolled actual methane emission rates for compliance purposes, you must demonstrate that the uncontrolled actual methane emissions have remained less than 14 tpy as determined monthly for 12 consecutive months. After such demonstration, you must determine the uncontrolled actual rolling 12-month determination methane emissions rates each month. The uncontrolled actual methane emissions must be calculated using a generally accepted model or calculation methodology which account for flashing, working, and breathing losses, and the calculations must be based on the actual average throughput, temperature, and separator pressure for the month. You may no longer comply with this paragraph and must instead comply with paragraph (a)(2) of this section if your storage vessel designated facility meets the conditions specified in paragraphs (a)(3)(i) or (ii) of this section.
(i) If a well feeding the storage vessel designated facility undergoes fracturing or refracturing, you must comply with paragraph (a)(2) of this section as soon as liquids from the well following fracturing or refracturing are routed to the storage vessel designated facility.
(ii) If the rolling 12-month emissions determination required in this section indicates that methane emissions increase to 14 tpy or greater from your storage vessel designated facility and the increase is not associated with fracturing or refracturing of a well feeding the storage vessel designated facility, you must comply with paragraph (a)(2) of this section within 30 days of the monthly determination.
(b) Control requirements. (1) Except as required in paragraph (b)(2) of this section, if you use a control device to reduce methane emissions from your storage vessel designated facility, you must meet all of the design and operational criteria specified in paragraphs (b)(1)(i) through (iv) of this section.
(i) Each storage vessel in the tank battery must be equipped with a cover that meets the requirements of § 60.5411c(b);
(ii) The storage vessels must be manifolded together with piping such that all vapors are shared among the headspaces of the storage vessels in the tank battery;
(iii) The tank battery must be equipped with one or more closed vent system that meets the requirements of § 60.5411c(a) and (c); and
(iv) The vapors collected in paragraphs (b)(1)(ii) and (iii) of this section must be routed to a control device that meets the conditions specified in § 60.5412c. As an alternative to routing the closed vent system to a control device, you may route the closed vent system to a process.
(2) For storage vessel designated facilities that do not have flashing emissions and that are not located at well sites or centralized production facilities, you may use a floating roof to reduce emissions. If you use a floating roof to reduce emissions, you must meet the requirements of § 60.112b(a)(1) or (2) and the relevant monitoring, inspection, recordkeeping, and reporting requirements in subpart Kb of this part. You must submit a statement that you are complying with § 60.112b(a)(1) or (2) with the initial annual report specified in § 60.5420c(b)(1) and (7).
(c) Requirements for storage vessel designated facilities that are removed from service or returned to service. If you remove a storage vessel designated facility from service or remove a portion of a storage vessel designated facility from service, you must comply with the applicable paragraphs (c)(1) through (4) of this section. A storage vessel is not a designated facility under this subpart for the period that it is removed from service.
(1) For a storage vessel designated facility to be removed from service, you must comply with the requirements of paragraphs (c)(1)(i) and (ii) of this section.
(i) You must completely empty and degas each storage vessel, such that each storage vessel no longer contains crude oil, condensate, produced water or intermediate hydrocarbon liquids. A storage vessel where liquid is left on walls, as bottom clingage or in pools due to floor irregularity is considered to be completely empty.
(ii) You must submit a notification as required in § 60.5420c(b)(7)(vii) in your next annual report, identifying each storage vessel designated facility removed from service during the reporting period and the date of its removal from service.
(2) For a portion of a storage vessel designated facility to be removed from service, you must comply with the requirements of paragraphs (c)(2)(i) through (iv) of this section.
(i) You must completely empty and degas the storage vessel(s), such that the storage vessel(s) no longer contains crude oil, condensate, produced water or intermediate hydrocarbon liquids. A storage vessel where liquid is left on walls, as bottom clingage or in pools due to floor irregularity is considered to be completely empty.
(ii) You must disconnect the storage vessel(s) from the tank battery by isolating the storage vessel(s) from the tank battery such that the storage vessel(s) is no longer manifolded to the tank battery by liquid or vapor transfer.
(iii) You must submit a notification as required in § 60.5420c(b)(7)(viii) in your next annual report, identifying each storage vessel removed from service during the reporting period, the impacted storage vessel designated facility, and the date of its removal from service.
(iv) The remaining storage vessel(s) in the tank battery remain a storage vessel designated facility and must continue to comply with the applicable requirements of paragraphs (a) and (b) of this section.
(3) If a storage vessel identified in paragraph (c)(1)(ii) or (c)(2)(iii) of this section is returned to service, you must determine its designated facility status as provided in § 60.5386c(e)(5).
(4) For each storage vessel designated facility or portion of a storage vessel designated facility returned to service during the reporting period, you must submit a notification in your next annual report as required in § 60.5420c(b)(7)(viii), identifying each storage vessel designated facility or portion of a storage vessel designated facility and the date of its return to service.
(d) Compliance, notification, recordkeeping, and reporting. You must comply with paragraphs (d)(1) through (3) of this section.
(1) You must demonstrate initial compliance with standards as required by § 60.5410c(h).
(2) You must demonstrate continuous compliance with standards as required by § 60.5415c(h).
(3) You must perform the required reporting as required by § 60.5420c(b)(1) and (7) and (b)(10) through (12), as applicable and the recordkeeping as required by § 60.5420c(c)(6) and (c)(7) through (12), as applicable.
(e) Exemptions. This subpart does not apply to storage vessels subject to and controlled in accordance with the requirements for storage vessels in subpart Kb of this part, and 40 CFR part 63, subparts G, CC, HH, or WW.
§ 60.5397c   What GHG standards apply to fugitive emissions components designated facilities?
This section applies to fugitive emissions components designated facilities. You must comply with the requirements of paragraphs (a) through (l) of this section to reduce fugitive emissions of methane. The requirements of this section are independent of the cover and closed vent system requirements of § 60.5411c.
(a) General requirements. You must monitor all fugitive emissions components in accordance with paragraphs (b) through (g) of this section. You must repair all sources of fugitive emissions in accordance with paragraph (h) of this section. You must demonstrate initial compliance in accordance with paragraph (i) of this section. You must keep records in accordance with paragraph (j) of this section and report in accordance with paragraph (k) of this section. You must meet the requirements for well closures in accordance with paragraph (l) of this section.
(b) Develop fugitive emissions monitoring plan. You must develop a fugitive emissions monitoring plan that covers all fugitive emissions components designated facilities within each company-defined area in accordance with paragraphs (c) and (d) of this section.
(c) Fugitive emissions monitoring plan. Your fugitive emissions monitoring plan must include the elements specified in paragraphs (c)(1) through (8) of this section, at a minimum.
(1) Frequency for conducting surveys. Surveys must be conducted at least as frequently as required by paragraphs (f) and (g) of this section.
(2) Technique for determining fugitive emissions ( i.e., AVO or other detection methods, Method 21 of appendix A-7 to this part; and/or OGI and meeting the requirements of paragraphs (c)(7)(i) through (vii) of this section).
(3) Manufacturer and model number of fugitive emissions detection equipment to be used, if applicable.
(4) Procedures and timeframes for identifying and repairing fugitive emissions components from which fugitive emissions are detected, including timeframes for fugitive emission components that are unsafe to repair. Your repair schedule must meet the requirements of paragraph (h) of this section at a minimum.
(5) Procedures and timeframes for verifying fugitive emission component repairs.
(6) Records that will be kept and the length of time records will be kept.
(7) If you are using OGI, your plan must also include the elements specified in paragraphs (c)(7)(i) through (vii) of this section.
(i) Verification that your OGI equipment meets the specifications of paragraphs (c)(7)(i)(A) and (B) of this section. This verification is an initial verification, and may either be performed by the facility, by the manufacturer, or by a third party. For the purposes of complying with the fugitive emissions monitoring program with OGI, fugitive emissions are defined as any visible emissions observed using OGI.
(A) Your OGI equipment must be capable of imaging gases in the spectral range for the compound of highest concentration in the potential fugitive emissions.
(B) Your OGI equipment must be capable of imaging a gas that is half methane, half propane at a concentration of 10,000 ppm at a flow rate of ≤60 g/hr from a quarter inch diameter orifice.
(ii) Procedure for a daily verification check.
(iii) Procedure for determining the operator's maximum viewing distance from the equipment and how the operator will ensure that this distance is maintained.
(iv) Procedure for determining maximum wind speed during which monitoring can be performed and how the operator will ensure monitoring occurs only at wind speeds below this threshold.
(v) Procedures for conducting surveys, including the items specified in paragraphs (c)(7)(v)(A) through (C) of this section.
(A) How the operator will ensure an adequate thermal background is present in order to view potential fugitive emissions.
(B) How the operator will deal with adverse monitoring conditions, such as wind.
(C) How the operator will deal with interferences ( e.g., steam).
(vi) Training and experience needed prior to performing surveys.
(vii) Procedures for calibration and maintenance. At a minimum, procedures must comply with those recommended by the manufacturer.
(8) If you are using Method 21 of appendix A-7 to this part, your plan must also include the elements specified in paragraphs (c)(8)(i) through (iv) of this section. For the purposes of complying with the fugitive emissions monitoring program using Method 21 of appendix A-7 to this part, a fugitive emission is defined as an instrument reading of 500 ppmv or greater.
(i) Verification that your monitoring equipment meets the requirements specified in Section 6.0 of Method 21 of appendix A-7 to this part. For purposes of instrument capability, the fugitive emissions definition shall be 500 ppmv or greater methane using a FID-based instrument. If you wish to use an analyzer other than a FID-based instrument, you must develop a site-specific fugitive emission definition that would be equivalent to 500 ppmv methane using a FID-based instrument ( e.g., 10.6 eV PID with a specified isobutylene concentration as the fugitive emission definition would provide equivalent response to your compound of interest).
(ii) Procedures for conducting surveys. At a minimum, the procedures shall ensure that the surveys comply with the relevant sections of Method 21 of appendix A-7 to this part, including Section 8.3.1.
(iii) Procedures for calibration. The instrument must be calibrated before use each day of its use by the procedures specified in Method 21 of appendix A-7 to this part. At a minimum, you must also conduct precision tests at the interval specified in Method 21 of appendix A-7 to this part, Section 8.1.2, and a calibration drift assessment at the end of each monitoring day. The calibration drift assessment must be conducted as specified in paragraph (c)(8)(iii)(A) of this section. Corrective action for drift assessments is specified in paragraphs (c)(8)(iii)(B) and (C) of this section.
(A) Check the instrument using the same calibration gas that was used to calibrate the instrument before use. Follow the procedures specified in Method 21 of appendix A-7 to this part, Section 10.1, except do not adjust the meter readout to correspond to the calibration gas value. If multiple scales are used, record the instrument reading for each scale used. Divide the arithmetic difference of the initial and post-test calibration response by the corresponding calibration gas value for each scale and multiply by 100 to express the calibration drift as a percentage.
(B) If a calibration drift assessment shows a negative drift of more than 10 percent, then all equipment with instrument readings between the fugitive emission definition multiplied by (100 minus the percent of negative drift) divided by 100 and the fugitive emission definition that was monitored since the last calibration must be re-monitored.
(C) If any calibration drift assessment shows a positive drift of more than 10 percent from the initial calibration value, then, at the owner/operator's discretion, all equipment with instrument readings above the fugitive emission definition and below the fugitive emission definition multiplied by (100 plus the percent of positive drift) divided by 100 monitored since the last calibration may be re-monitored.
(iv) Procedures for monitoring yard piping (other than buried yard piping). At a minimum, place the probe inlet at the surface of the yard piping and run the probe down the length of the piping. Connection points on the piping must be monitored following the procedures specified in Method 21 of appendix A-7 to this part.
(d) Additional elements of fugitive emissions monitoring plan. Each fugitive emissions monitoring plan must include the elements specified in paragraphs (d)(1) and (2) of this section, at a minimum, as applicable.
(1) If you are using OGI, your plan must include procedures to ensure that all fugitive emissions components, except buried yard piping and associated components ( e.g., connectors), are monitored during each survey. Example procedures include, but are not limited to, a sitemap with an observation path, a written narrative of where the fugitive emissions components are located and how they will be monitored, or an inventory of fugitive emissions components.
(2) If you are using Method 21 of appendix A-7 to this part, your plan must include a list of fugitive emissions components to be monitored and method for determining the location of fugitive emissions components to be monitored in the field ( e.g., tagging, identification on a process and instrumentation diagram, etc.). Your fugitive emissions monitoring plan must include the written plan developed for all of the fugitive emissions components designated as difficult-to-monitor in accordance with paragraph (g)(2) of this section, and the written plan for fugitive emissions components designated as unsafe-to-monitor in accordance with paragraph (g)(3) of this section.
(e) Monitoring of fugitive emissions components. Each fugitive emissions component, except buried yard piping and associated components ( e.g., connectors), shall be observed or monitored for fugitive emissions during each monitoring survey.
(f) Initial monitoring survey. You must conduct initial monitoring surveys according to the requirements specified in paragraphs (f)(1) through (3) of this section.
(1) At single wellhead only sites and small sites, you must conduct an initial monitoring survey using audible, visual, and olfactory (AVO), or any other detection methods ( e.g., OGI), within 90 days of the startup of production, for each fugitive emissions components designated facility or by 90 days after the state plan submittal deadline (as specified in § 60.5362c(c)), whichever date is later.
(2) For multi-wellhead only well sites, well sites or centralized production facilities that contain the major production and processing equipment specified in paragraphs (g)(1)(iv)(A), (B), (C), or (D) of this section, and compressor station sites, you must conduct an initial monitoring survey using OGI or Method 21 to appendix A-7 to this part within 90 days of the effective date of your state or Tribal plan, for each fugitive emissions components designated facility, or by 36 months after the state plan submittal deadline (as specified in § 60.5362c(c)), whichever date is later.
(3) Notwithstanding the deadlines, specified in paragraphs (f)(1) through (3) of this section for each fugitive emissions components designated facility located on the Alaskan North Slope, that would be subject to monitoring between September and March, you must conduct an initial monitoring survey within 6 months, or by the following June 30, whichever date is latest.
(g) Monitoring frequency. A monitoring survey of each fugitive emissions components designated facility must be performed as specified in paragraph (g)(1) of this section, with the exceptions noted in paragraphs (g)(2) through (4) of this section. Monitoring for fugitive emissions components designated facilities located at well sites and centralized production facilities that have wells located onsite must continue at the specified frequencies in paragraphs (g)(1)(i), (ii), (iii), (iv) and (vi) of this section until the well closure requirements of paragraph (l) of this section are completed.
(1) A monitoring survey of the fugitive emissions components designated facilities must be conducted using the methods and at the frequencies specified in paragraphs (g)(1)(i) through (vi) of this section.
(i) A monitoring survey of the fugitive emissions component designated facilities located at single wellhead only well sites must be conducted at least quarterly using AVO, or any other detection method after the initial survey, except as specified in paragraph (g)(1)(vi) of this section. Any indications of fugitive emissions using these methods are considered fugitive emissions that must be repaired in accordance with paragraph (h) of this section.
(ii) A monitoring survey of the fugitive emissions component designated facilities located at small well sites must be conducted at least quarterly using AVO, or any other detection method, after the initial survey except as specified in paragraph (g)(1)(vi) of this section. Any indications of fugitive emissions using these methods are considered fugitive emissions that must be repaired in accordance with paragraph (h) of this section. At small well sites with an uncontrolled storage vessel, a visual inspection of all thief hatches and other openings on the storage vessel that are fugitive emissions components must be conducted in conjunction with the monitoring survey to ensure that they are kept closed and sealed at all times except during times of adding or removing material, inspecting or sampling material, or during required maintenance operations. If evidence of a deviation from this requirement is found, you must take corrective action. At small well sites with a separator, a visual inspection of all separator dump valves to ensure the dump valve is free of debris and not stuck in an open position must be conducted in conjunction with the monitoring survey. Any dump valve not operating as designed must be repaired.
(iii) A monitoring survey of the fugitive emissions components designated facilities located at multi-wellhead only well sites must be conducted in accordance with paragraphs (g)(1)(iii)(A) and (B) of this section, except as specified in paragraph (g)(1)(vi) of this section.
(A) A monitoring survey must be conducted at least quarterly using AVO, or any other detection method after the initial survey. Any indications of fugitive emissions using these methods are considered fugitive emissions that must be repaired in accordance with paragraph (h) of this section.
(B) A monitoring survey must be conducted at least semiannually using OGI or Method 21 of appendix A-7 to this part after the initial survey. Consecutive semiannual surveys must be conducted at least 4 months apart and no more than 7 months apart.
(iv) A monitoring survey of the fugitive emissions components designated facilities located at well sites or centralized production facilities that contain the major production and processing equipment specified in paragraphs (g)(1)(iv)(A), (B), (C), or (D) of this section must be conducted at the frequencies in paragraphs (g)(1)(iv)(E) and (F) of this section, except as specified in paragraph (g)(1)(vi) of this section.
(A) One or more controlled storage vessels or tank batteries.
(B) One or more control devices.
(C) One or more natural gas-driven process controllers or pumps.
(D) Two or more pieces of major production and processing equipment not specified in paragraphs (g)(1)(iv)(A) through (C) of this section.
(E) A monitoring survey must be conducted at least bimonthly using AVO, or any other detection method after the initial survey. Any indications of fugitive emissions using these methods are considered fugitive emissions that must be repaired in accordance with paragraph (h) of this section. A visual inspection of all thief hatches and other openings on storage vessels (or tank batteries) that are fugitive emissions components must be conducted in conjunction with the monitoring survey to ensure that they are kept closed and sealed at all times except during times of adding or removing material, inspecting or sampling material, or during required maintenance operations. If evidence of a deviation from this requirement is found, you must take corrective action. A visual inspection must be conducted of all separator dump valves to ensure the dump valve is free of debris and not stuck in an open position must be conducted in conjunction with the monitoring survey. Any dump valve not operating as designed must be repaired.
(F) A monitoring survey must be conducted at least quarterly using OGI or Method 21 of appendix A-7 to this part after the initial survey. Consecutive quarterly monitoring surveys must be conducted at least 60 calendar days apart.
(v) A monitoring survey of the fugitive emissions components designated facility located at a compressor station must be conducted at the frequencies in paragraphs (g)(1)(v)(A) and (B) of this section, except as specified in paragraph (g)(1)(vi) of this section.
(A) A monitoring survey must be conducted at least monthly using AVO, or any other detection method after the initial survey. Any indications of fugitive emissions using these methods are considered fugitive emissions that must be repaired in accordance with paragraph (h) of this section.
(B) A monitoring survey must be conducted at least quarterly using OGI or Method 21 of appendix A-7 to this part after the initial survey. Consecutive quarterly monitoring surveys must be conducted at least 60 calendar days apart.
(vi) A monitoring survey of the fugitive emissions components designated facility located on the Alaska North Slope must be conducted using OGI of this part or Method 21 to appendix A-7 to this part at least annually. Consecutive annual monitoring surveys must be conducted at least 9 months apart and no more than 13 months apart.
(2) If you are using Method 21 of appendix A-7 to this part, fugitive emissions components that cannot be monitored without elevating the monitoring personnel more than 2 meters above the surface may be designated as difficult-to-monitor. Fugitive emissions components that are designated difficult-to-monitor must meet the specifications of paragraphs (g)(2)(i) through (iv) of this section.
(i) A written plan must be developed for all the fugitive emissions components designated difficult-to-monitor. This written plan must be incorporated into the fugitive emissions monitoring plan required by paragraphs (b), (c), and (d) of this section.
(ii) The plan must include the identification and location of each fugitive emissions component designated as difficult-to-monitor.
(iii) The plan must include an explanation of why each fugitive emissions component designated as difficult-to-monitor is difficult-to-monitor.
(iv) The plan must include a schedule for monitoring the difficult-to-monitor fugitive emissions components at least once per calendar year.
(3) If you are using Method 21 of appendix A-7 to this part, fugitive emissions components that cannot be monitored because monitoring personnel would be exposed to immediate danger while conducting a monitoring survey may be designated as unsafe-to-monitor. Fugitive emissions components that are designated unsafe-to-monitor must meet the specifications of paragraphs (g)(3)(i) through (iv) of this section.
(i) A written plan must be developed for all the fugitive emissions components designated unsafe-to-monitor. This written plan must be incorporated into the fugitive emissions monitoring plan required by paragraphs (b), (c), and (d) of this section.
(ii) The plan must include the identification and location of each fugitive emissions component designated as unsafe-to-monitor.
(iii) The plan must include an explanation of why each fugitive emissions component designated as unsafe-to-monitor is unsafe-to-monitor.
(iv) The plan must include a schedule for monitoring the fugitive emissions components designated as unsafe-to-monitor.
(4) The requirements of paragraphs (g)(1)(iv)(F) and (g)(1)(v)(B) of this section are waived during a quarterly monitoring period for any fugitive emissions components designated facility located within an area that has an average calendar month temperature below 0 degrees Fahrenheit for two of three consecutive calendar months of a quarterly monitoring period. The calendar month temperature average for each month within the quarterly monitoring period must be determined using historical monthly average temperatures over the previous three years as reported by a National Oceanic and Atmospheric Administration source or other source approved by the Administrator. The requirements of paragraph (g)(1)(iv) and (v) of this section shall not be waived for two consecutive quarterly monitoring periods.
(h) Repairs. Each identified source of fugitive emissions shall be repaired in accordance with paragraphs (h)(1) and (2) of this section.
(1) A first attempt at repair shall be made in accordance with paragraphs (h)(1)(i) and (ii) of this section.
(i) A first attempt at repair shall be made no later than 15 calendar days after detection of fugitive emissions that were identified using AVO.
(ii) If you are complying with paragraph (g)(1)(i) through (vi) of this section using OGI or Method 21 of appendix A-7 to this part, a first attempt at repair shall be made no later than 30 calendar days after detection of the fugitive emissions.
(2) Repair shall be completed as soon as practicable, but no later than 15 calendar days after the first attempt at repair as required in paragraph (h)(1)(i) of this section, and 30 calendar days after the first attempt at repair as required in paragraph (h)(1)(ii) of this section.
(3) Delay of repair will be allowed if the conditions in paragraphs (h)(3)(i) or (ii) of this section are met.
(i) If the repair is technically infeasible, would require a vent blowdown, a compressor station shutdown, a well shutdown or well shut-in, or would be unsafe to repair during operation of the unit, the repair must be completed during the next scheduled compressor station shutdown for maintenance, scheduled well shutdown, scheduled well shut-in, after a scheduled vent blowdown, or within 2 years of detecting the fugitive emissions, whichever is earliest. A vent blowdown is the opening of one or more blowdown valves to depressurize major production and processing equipment, other than a storage vessel.
(ii) If the repair requires replacement of a fugitive emissions component or a part thereof, but the replacement cannot be acquired and installed within the repair timelines specified in paragraphs (h)(1) and (2) of this section due to either of the conditions specified in paragraphs (h)(3)(ii)(A) or (B) of this section, the repair must be completed in accordance with paragraph (h)(3)(ii)(C) of this section and documented in accordance with § 60.5420c(c)(13)(v)(I).
(A) Valve assembly supplies had been sufficiently stocked but are depleted at the time of the required repair.
(B) A replacement fugitive emissions component or a part thereof requires custom fabrication.
(C) The required replacement must be ordered no later than 10 calendar days after the first attempt at repair. The repair must be completed as soon as practicable, but no later than 30 calendar days after receipt of the replacement component, unless the repair requires a compressor station or well shutdown. If the repair requires a compressor station or well shutdown, the repair must be completed in accordance with the timeframe specified in paragraph (h)(3)(i) of this section.
(4) Each identified source of fugitive emissions must be resurveyed to complete repair according to the requirements of paragraphs (h)(4)(i) through (v) of this section, to ensure that there are no fugitive emissions.
(i) The operator may resurvey the fugitive emissions components to verify repair using either Method 21 of appendix A-7 to this part or OGI, except as specified in paragraph (h)(4)(v) of this section.
(ii) For each repair that cannot be made during the monitoring survey when the fugitive emissions are initially found, a digital photograph must be taken of that component, or the component must be tagged during the monitoring survey when the fugitive emissions were initially found for identification purposes and subsequent repair. The digital photograph must include the date that the photograph was taken and must clearly identify the component by location within the site ( e.g., the latitude and longitude of the component or by other descriptive landmarks visible in the picture).
(iii) Operators that use Method 21 of appendix A-7 to this part to resurvey the repaired fugitive emissions components are subject to the resurvey provisions specified in paragraphs (h)(4)(iii)(A) and (B) of this section.
(A) A fugitive emissions component is repaired when the Method 21 instrument indicates a concentration of less than 500 ppmv above background or when no soap bubbles are observed when the alternative screening procedures specified in section 8.3.3 of Method 21 of appendix A-7 to this part are used.
(B) Operators must use the Method 21 monitoring requirements specified in paragraph (c)(8)(ii) of this section or the alternative screening procedures specified in section 8.3.3 of Method 21 of appendix A-7 to this part.
(iv) Operators that use OGI to resurvey the repaired fugitive emissions components are subject to the resurvey provisions specified in paragraphs (h)(4)(iv)(A) and (B) of this section.
(A) A fugitive emissions component is repaired when the OGI instrument shows no indication of visible emissions.
(B) Operators must use the OGI monitoring requirements specified in paragraph (c)(7) of this section.
(v) For fugitive emissions identified using AVO detection methods, the operator may resurvey using those same methods, Method 21 of appendix A-7 to this part, or OGI. For operators that use AVO detection methods, a fugitive emissions component is repaired when there are no indications of fugitive emissions using these methods.
(i) Initial compliance. You must demonstrate initial compliance with the standards that apply to fugitive emissions components designated facilities as required by § 60.5410c(i).
(j) Continuous compliance. You must demonstrate continuous compliance with the standards that apply to fugitive emissions components designated facilities as required by § 60.5415c(j).
(k) Reporting and recordkeeping. You must comply with the reporting requirements as specified in § 60.5420c(b)(1) and (8), and the recordkeeping requirements as specified in § 60.5420c(c)(13).
(l) Well closure requirements. You must complete the requirements specified in paragraphs (l)(1) through (4) of this section.
(1) You must submit a well closure plan to the Administrator within 30 days of the cessation of production from all wells located at the well site as specified in § 60.5420c(a)(4)(i). The well closure plan must include, at a minimum, the information specified in paragraphs (l)(1)(i) through (iii) of this section.
(i) Description of the steps necessary to close all wells at the well site, including permanent plugging of all wells;
(ii) Description of the financial requirements and disclosure of financial assurance to complete closure; and
(iii) Description of the schedule for completing all activities in the well closure plan.
(2) You must submit a notification as specified in § 60.5420c(a)(4)(ii) of intent to close the well site to the Administrator 60 days before you begin well closure activities.
(3) You must conduct a survey of the well site using OGI, including each closed well, after completing all well closure activities outlined in the well closure plan specified in paragraph (l)(1) of this section. If any emissions are imaged by the OGI instrument, then you must take steps to eliminate those emissions and you must resurvey the source of emissions. You must repeat steps to eliminate emissions and resurvey the source of emissions until no emissions are imaged by the OGI instrument. You must update the well closure plan specified in paragraph (l)(1) of this section to include the video of the OGI survey demonstrating closure of all wells at the site.
(4) You must maintain the records specified in § 60.5420c(c)(13) and submit the reports specified in § 60.5420c(b)(8).
§ 60.5398c   What alternative GHG standards apply to fugitive emissions components designated facilities and what inspection and monitoring requirements apply to covers and closed vent systems when using an alternative technology?
This section provides alternative GHG standards for fugitive emissions components designated facilities in § 60.5397c and alternative continuous inspection and monitoring requirements for covers and closed vent systems in § 60.5416c(a)(1)(ii) and (iii), (2)(ii) through (iv), and (3)(iii) and (iv). If you choose to use an alternative standard under this section, you must submit the notification under paragraph (a) of this section. If you choose to demonstrate compliance with the alternative GHG standards through periodic screening, you are subject to the requirements in paragraph (b) of this section. If you choose to demonstrate compliance through a continuous monitoring system, you are subject to the requirements in paragraph (c) of this section. The technology used for periodic screenings under paragraph (b) of this section or continuous monitoring under paragraph (c) of this section must be approved in accordance with § 60.5398b(d).
(a) Notification. If you choose to demonstrate compliance with the alternative GHG standards in either paragraph (b) or (c) of this section, you must notify the Administrator of adoption of the alternative standards in the first annual report following implementation of the alternative standards, as specified in § 60.5424c(a). Once you have implemented the alternative standards, you must continue to comply with the alternative standards.
(b) Periodic screening. You may choose to demonstrate compliance for your fugitive emissions components designated facility and compliance with continuous inspection and monitoring requirements for your covers and closed vent systems through periodic screenings using any methane measurement technology approved in accordance with § 60.5398b(d). If you choose to demonstrate compliance using periodic screenings, you must comply with the requirements in paragraphs (b)(1) through (5) of this section and comply with the recordkeeping and reporting requirements in § 60.5424c.
(1) You must use one or more alternative test method(s) approved per § 60.5398b(d) to conduct periodic screenings.
(i) The required frequencies for conducting periodic screenings are listed in tables 2 and 3 to this subpart. You must choose the appropriate frequency for conducting periodic screenings based on the minimum aggregate detection threshold of the method used to conduct the periodic screenings. You must also use tables 2 and 3 to this subpart to determine whether you must conduct an annual fugitive emissions survey using OGI, except as provided in paragraph (b)(1)(ii) of this section.
(ii) Use of table 2 or 3 to this subpart is based on the required frequency for conducting monitoring surveys in § 60.5397c(g)(1)(i) through (v).
(iii) You may replace one or more individual periodic screening events required by table 2 or 3 to this subpart with an OGI survey. The OGI survey must be conducted according to the requirements outlined in § 60.5397c.
(iv) If you use multiple methods to conduct periodic screenings, you must conduct all periodic screenings, regardless of the method used for the individual periodic screening event, at the frequency required for the alternative test method with the highest aggregate detection threshold ( e.g., if you use methods with aggregate detection thresholds of 15 kg/hr, your periodic screenings must be conducted monthly). You must also conduct an annual OGI survey if an annual OGI survey is required for the alternative test method with the highest aggregate detection threshold.
(2) You must develop a monitoring plan that covers the collection of fugitive emissions components, covers, and closed vent systems at each site where you will use periodic screenings to demonstrate compliance. You may develop a site-specific monitoring plan, or you may include multiple sites that you own or operate in one plan. At a minimum, the monitoring plan must contain the information specified in paragraphs (b)(2)(i) through (ix) of this section.
(i) Identification of each site that will be monitored through periodic screening, including latitude and longitude coordinates of the site in decimal degrees to an accuracy and precision of five decimals of a degree using the North American Datum of 1983.
(ii) Identification of the alternative test method(s) approved per § 60.5398b(d) that will be used for periodic screenings and the spatial resolution ( i.e., component-level, area-level, or facility-level) of the technology used for each method.
(iii) Identification of and contact information for the entities that will be performing the periodic screenings.
(iv) Required frequency for conducting periodic screenings, based on the criteria outlined in paragraph (b)(1) of this section.
(v) If you are required to conduct an annual OGI survey by paragraph (b)(1)(i) or (iii) of this section or you choose to replace any individual screening event with an OGI survey, your monitoring plan must also include the information required by § 60.5397c(b).
(vi) Procedures for conducting monitoring surveys required by paragraphs (b)(5)(ii)(A), (b)(5)(iii)(A), and (b)(5)(iv)(A) of this section. At a minimum, your monitoring plan must include the information required by § 60.5397c(c)(2), (3), (7), and (8) and § 60.5397c(d), as applicable. The provisions of § 60.5397c(d)(3) do not apply for purposes of conducting monitoring surveys required by paragraphs (b)(5)(ii) through (iv) of this section.
(vii) Procedures and timeframes for identifying and repairing fugitive emissions components, covers, and closed vent systems from which emissions are detected.
(viii) Procedures and timeframes for verifying repairs for fugitive emissions components, covers, and closed vent systems.
(ix) Records that will be kept and the length of time records will be kept.
(3) You must conduct the initial screening of your site according to the timeframes specified in (b)(3)(i) and (ii) of this section.
(i) Within 90 days of the effective date of your state or Tribal plan for each fugitive emissions components designated facility and storage vessel designated facility located at a well site.
(ii) No later than the final date by which the next monitoring survey required by § 60.5397c(g)(1)(i) through (v) would have been required to be conducted if you were previously complying with the requirements in § 60.5397c and § 60.5416c.
(4) If you are required to conduct an annual OGI survey by paragraph (b)(1)(i) or (iii) of this section, you must conduct OGI surveys according to the schedule in paragraphs (b)(4)(i) through (iv) of this section.
(i) You must conduct the initial OGI survey no later than 12 calendar months after conducting the initial screening survey in paragraph (b)(3) of this section.
(ii) Each subsequent OGI survey must be conducted no later than 12 calendar months after the previous OGI survey was conducted. Each identified source of fugitive emissions during the OGI survey shall be repaired in accordance with § 60.5397c(h).
(iii) If you replace a periodic screening event with an OGI survey or you are required to conduct a monitoring survey in accordance with paragraph (b)(5)(ii)(A) of this section prior to the date that your next OGI survey under paragraph (b)(4)(ii) of this section is due, the OGI survey conducted in lieu of the periodic screening event or the monitoring survey under paragraph (b)(5)(ii)(A) of this section can be used to fulfill the requirements of paragraph (b)(4)(ii) of this section. The next OGI survey is required to be conducted no later than 12 calendar months after the date of the survey conducted under paragraph (b)(1)(iv) or (b)(5)(ii)(A) of this section.
(iv) You cannot use a monitoring survey conducted under paragraph (b)(5)(iii)(A) or (b)(5)(iv)(A) of this section to fulfill the requirements of paragraph (b)(4)(ii) of this section unless the monitoring survey included all fugitive emission components at the site.
(5) You must investigate confirmed detections of emissions from periodic screening events and repair each identified source of emissions in accordance with paragraphs (b)(5)(i) through (vi) of this section.
(i) You must receive the results of the periodic screening no later than 5 calendar days after the screening event occurs.
(ii) If you use an alternative test method with a facility-level spatial resolution to conduct a periodic screening event and the results of the periodic screening event indicate a confirmed detection of emissions from a designated facility, you must take the actions listed in paragraphs (b)(5)(ii)(A) through (C) of this section.
(A) You must conduct a monitoring survey of all the fugitive emissions components in a designated facility using either OGI or EPA Method 21 to appendix A-7 of this part. You must follow the procedures in your monitoring plan when conducting the survey.
(B) You must inspect all covers and closed vent system(s) with OGI or Method 21 of appendix A-7 to this part in accordance with the requirements in § 60.5416c(b)(1) through (4), as applicable.
(C) You must conduct a visual inspection of all covers and closed vent systems to identify if there are any defects, as defined in § 60.5416c(a)(1)(ii), § 60.5416c(a)(2)(iii), or § 60.5416c(a)(3)(i), as applicable.
(iii) If you use an alternative test method with an area-level spatial resolution to conduct a periodic screening event and the results of the periodic screening event indicate a confirmed detection of emissions from a designated facility, you must take the actions listed in paragraphs (b)(5)(iii)(A) and (B) of this section, as applicable.
(A) You must conduct a monitoring survey of all the fugitive emissions components located within a 4-meter radius of the location of the periodic screening's confirmed detection using either OGI or EPA Method 21 to appendix A-7 of this part. You must follow the procedures in your monitoring plan when conducting the survey.
(B) If the confirmed detection occurred in the portion of a site that contains a storage vessel or a closed vent system, you must inspect all covers and all closed vent systems that are connected to all storage vessels and closed vent systems that are within a 2-meter radius of the location of the periodic screening's confirmed detection ( i.e., you must inspect the whole system that is connected to the portion of the system in the radius of the detected event, not just the portion of the system that falls within the radius of the detected event).
( 1 ) You must inspect the cover(s) and closed vent system(s) with OGI or Method 21 of appendix A-7 to this part in accordance with the requirements in § 60.5416c(b)(1) through (4), as applicable.
( 2 ) You must conduct a visual inspection of the closed vent system(s) and cover(s) to identify if there are any defects, as defined in § 60.5416c(a)(1)(ii), § 60.5416c(a)(2)(iii), or § 60.5416c(a)(3)(i), as applicable.
(iv) If you use an alternative test method with a component-level spatial resolution to conduct a periodic screening event and the results of the periodic screening event indicate a confirmed detection of emissions from a designated facility, you must take the actions listed in paragraphs (b)(5)(iv)(A) and (B) of this section, as applicable.
(A) You must conduct a monitoring survey of all the fugitive emissions components located within a 1-meter radius of the location of the periodic screening's confirmed detection using either OGI or EPA Method 21 to appendix A-7 of this part. You must follow the procedures in your monitoring plan when conducting the survey.
(B) If the confirmed detection occurred in the portion of a site that contains a storage vessel or a closed vent system, you must inspect all covers and all closed vent systems that are connected to all storage vessels and closed vent systems that are within a 0.5-meter radius of the location of the periodic screening's confirmed detection ( i.e., you must inspect the whole system that is connected to the portion of the system in the radius of the detected event, not just the portion of the system that falls within the radius of the detected event).
( 1 ) You must inspect the cover(s) and closed vent system(s) with OGI or Method 21 of appendix A-7 to this part in accordance with the requirements in § 60.5416c(b)(1) through (4), as applicable.
( 2 ) You must conduct a visual inspection of the closed vent system(s) and cover(s) to identify if there are any defects, as defined in § 60.5416c(a)(1)(ii), § 60.5416c(a)(2)(iii), or § 60.5416c(a)(3)(i), as applicable.
(v) You must repair all sources of fugitive emissions in accordance with § 60.5397c(h) and all emissions or defects of covers and closed vent systems in accordance with § 60.5416c(b)(4), except as specified in this paragraph (b)(5)(v). Except as allowed by §§ 60.5397c(h)(3) and 60.5416c(b)(5), all repairs must be completed, including the resurvey verifying the repair, within 30 days of receiving the results of the periodic screening in paragraph (b)(5)(i) of this section.
(vi) If the results of the periodic screening event in paragraph (b)(5)(i) of this section indicate a confirmed detection at a designated facility, and the ground-based monitoring survey and inspections required by paragraphs (b)(5)(ii) through (iv) of this section demonstrate the confirmed detection was caused by a failure of a control device used to demonstrate continuous compliance under this subpart, you must initiate an investigative analysis to determine the underlying primary and other contributing cause(s) of such failure within 24 hours of receiving the results of the monitoring survey and/or inspection. As part of the investigation, you must determine if the control device is operating in compliance with the applicable requirements of §§ 60.5415c and 60.5417c, and if not, what actions are necessary to bring the control device into compliance with those requirements as soon as possible and prevent future failures of the control device from the same underlying cause(s).
(vii) If the results of the inspections required in paragraphs (b)(5)(ii) through (iv) of this section indicate that there is an emission or defect in your cover or closed vent system, you must perform an investigative analysis to determine the underlying primary and other contributing cause(s) of emissions from your cover or closed vent system within 5 days of completing the inspection required by paragraphs (b)(5)(ii) through (iv) of this section. The investigative analysis must include a determination as to whether the system was operated outside of the engineering design analysis and whether updates are necessary for the cover or closed vent system to prevent future emissions from the cover and closed vent system.
(6) You must maintain the records as specified in § 60.5420c(c)(3) through (c)(6), (c)(13) and (c)(14) and § 60.5424c(c).
(7) You must submit reports as specified in § 60.5424c.
(c) Continuous Monitoring. You may choose to demonstrate compliance for your fugitive emissions components designated facility and compliance with continuous inspection and monitoring requirements for your covers and closed vent systems through continuous monitoring using a technology approved in accordance with § 60.5398b(d). If you choose to demonstrate compliance using continuous monitoring, you must comply and develop a monitoring plan consistent with the requirements in paragraphs (c)(1) through (9) of this section and comply with the recordkeeping and reporting requirements in § 60.5424c.
(1) For the purpose of this section, continuous monitoring means the ability of a methane monitoring system to determine and record a valid methane mass emissions rate or equivalent of designated facilities at least once for every 12-hour block.
(i) The detection threshold of the system must be such that it can detect at least 0.40 kg/hr (0.88 lb/hr) of methane.
(ii) The health of the devices used within the continuous monitoring system must be confirmed for power and function at least twice every six-hour block.
(iii) The continuous monitoring system must transmit all applicable valid data at least once every 24-hours. The continuous monitoring system must transmit all valid data collected, including health checks required in paragraph (c)(1)(ii) of this section.
(iv) The continuous monitoring system must continuously collect data as specified in paragraph (c)(1) of this section, except as specified in paragraphs (c)(1)(iv)(A) through (D) of this section:
(A) The rolling 12-month average operational downtime of the continuous monitoring system must be less than or equal to 10 percent.
(B) Operational downtime of the continuous monitoring system is defined as a period of time for which any monitor fails to collect or transmit data as specified in paragraph (c)(1) of this section or any monitor is out-of-control as specified in paragraph (c)(1)(iv)(C) of this section.
(C) A monitor is out-of-control if it fails ongoing quality assurance checks, as specified in the alternative test method approved under § 60.5398b(d), or if the monitor output is outside of range. The beginning of the out-of-control period is defined as the time of the failure of the quality assurance check. The end of the out-of-control period is defined as the time when either the monitor passes a subsequent quality assurance check, or a new monitor is installed. The out-of-control period for a monitor outside of range starts at the time when the monitor first reads outside of range and ends when the monitor reads within range again.
(D) The downtime for the continuous monitoring system must be calculated each calendar month. Once 12 months of data are available, at the end of each calendar month, you must calculate the 12-month average by averaging that month with the previous 11 calendar months. You must determine the rolling 12-month average by recalculating the 12-month average at the end of each month.
(2) You must develop a monitoring plan that covers the collection of fugitive emissions components, covers, and closed vent systems for each site where continuous monitoring will be used to demonstrate compliance. At a minimum, the monitoring plan must contain the information specified in paragraphs (c)(2)(i) through (xii) of this section.
(i) Identification of each site to be monitored through continuous monitoring, including latitude and longitude coordinates of the site in decimal degrees to an accuracy and precision of at least four decimals of a degree using the North American Datum of 1983.
(ii) Identification of the approved alternative test method(s) approved under § 60.5398b(d) used for the continuous monitoring, including the detection principle; the manufacturer, make, and model; instrument manual, if applicable; and the manufacturer's recommended maintenance schedule.
(iii) If the continuous monitoring system is administered through a third-party provider, contact information where the provider can be reached 24 hours a day.
(iv) Number and location of monitors. If the continuous monitoring system uses open path technology, you must identify the location of any reflectors used. These locations should be identified by latitude and longitude coordinates in decimal degrees to an accuracy and precision of at least five decimals of a degree using the North American Datum of 1983.
(v) Discussion of system calibration requirements, including but not limited to, the calibration procedures and calibration schedule for the detection systems and meteorology systems.
(vi) Identification of critical components and infrastructure ( e.g., power, data systems) and procedures for their repairs.
(vii) Procedures for out-of-control periods.
(viii) Procedures for establishing baseline emissions, including the identification of any sources with methane emissions not subject to this subpart. The procedures for establishing the baseline emissions must account for variability in the operation of the site. Operation of the site during the development of the baseline emissions must represent the site's expected annual production or throughput.
(ix) Procedures for determining when a fugitive emissions event is detected by the continuous monitoring technology.
(x) Procedures and timeframes for identifying and repairing fugitive emissions components, covers, and closed vent systems from which emissions are detected.
(xi) Procedures and timeframes for verifying repairs for fugitive emissions components, covers, and closed vent systems.
(xii) Records that will be kept and the length of time records will be kept.
(3) You must install and begin conducting monitoring with your continuous monitoring system according to the timeframes specified in paragraphs (c)(3)(i) and (ii) of this section.
(i) Within 120 days of the effective date of your state or Tribal plan for each fugitive emissions components designated facility and storage vessel designated facility located at a well site.
(ii) No later than the final date by which the next monitoring survey required by § 60.5397c(g)(1)(i) through (v) would have been required to be conducted if you were previously complying with the requirements in § 60.5397c and § 60.5416c.
(4) You are subject to the following action-levels as specified in paragraphs (c)(4)(i) and (ii) of this section for any designated facilities located at a well site, centralized production facility, or compressor station.
(i) For designated facilities located at a wellhead only well site, the action levels are as follows.
(A) The 90-day rolling average action-level is 1.2 kg/hr (2.6 lbs/hr) of methane over the site-specific baseline emissions.
(B) The 7-day rolling average action level is 15 kg/hr (34 lbs/hr) of methane over site-specific baseline emissions.
(ii) For designated facilities located at well sites with major production and processing equipment (including small well sites), centralized production facilities, and compressor stations, the action levels are as follows.
(A) The 90-day rolling average action-level is 1.6 kg/hr (3.6 lbs/hr) of methane over the site-specific baseline emissions.
(B) The rolling 7-day average action level is 21 kg/hr (46 lbs/hr) of methane over the site-specific baseline emissions.
(5) You must establish site-specific baseline emissions upon initial installation and activation of a continuous monitoring system. You must establish the baseline emissions under the conditions outlined in paragraphs (c)(5)(i) through (iii) of this section. You must determine the baseline emission rates according to paragraphs (c)(5)(iv) and (v) of this section. The baseline must be established initially and any time there is a major change to the processing equipment at a well site (including small well sites), centralized production facility, or compressor station.
(i) Inspect all fugitive emissions components according to the requirements in § 60.5397c and covers and closed vent systems according to the requirements in § 60.5416c. This includes all fugitive emissions components, covers, and closed vent systems, regardless of whether they are regulated by this subpart. Repairs of any fugitive emissions, leaks, or defects found during the inspection must be completed prior to beginning the period in paragraph (c)(5)(iii) of this section.
(ii) Verify control devices ( e.g., flares) on all affected sources are operating in compliance with the applicable requirements of §§ 60.5415c and 60.5417c. You must ensure that all control devices are operating in compliance with the applicable regulations prior to beginning the period in paragraph (c)(5)(iii) of this section. Verify that all other methane emission sources ( e.g., reciprocating engines) located at the site are operating consistent with any applicable regulations. You must ensure that these sources are operating in compliance with the applicable regulations prior to beginning the period in paragraph (c)(5)(iii) of this section.
(iii) Using the alternative test method approved per § 60.5398b(d), record the site-level emission rate from your continuous monitoring system for 30 operating days. You must minimize any activities that are not normal, day-to-day activities during this 30 operating day period. Document any maintenance activities and the period (including the start date and time and end date and time) such activities occurred during the 30 operating day period.
(iv) Determine the site-specific baseline by calculating the mean emission rate (kg/hr of methane) for the 30 operating day period, less any time periods when maintenance activities were conducted.
(v) The site-specific baseline emission rate must be no more than 10 times the applicable 90-day action-level defined in paragraphs (c)(4)(i) and (c)(4)(ii) of this section.
(6) Calculate the emission rate from your site according to paragraphs (c)(6)(i) through (iii) of this section. Compare the emission rate calculated in this paragraph (c)(6) to the appropriate action levels in paragraph (c)(4) of this section to determine whether you have exceeded an action level.
(i) Each calendar day, calculate the daily average mass emission rate in kg/hr of methane from your continuous monitoring system.
(ii) Once the system has been operating for 7 calendar days, at the end of each calendar day calculate the 7-day average mass emission rate by averaging the mass emission rate from that day with the mass emission rate from the previous 6 calendar days. Subtract the site-specific baseline mass emission rate from the 7-day average mass emission rate when comparing the mass emission rate to the applicable action level. Determine the 7-day rolling average by recalculating the 7-day average each calendar day, less the site-specific baseline.
(iii) Once the system has been operating for 90 calendar days, at the end of each calendar day calculate the 90-day average mass emission rate by averaging the mass emission rate from that day with the mass emission rate from the previous 89 calendar days. Subtract the site-specific baseline emission rate from the 90-day average mass emission rate when comparing the mass emission rate to the applicable action level. Determine the 90-day rolling average by recalculating the 90-day average each calendar day, less the site-specific baseline.
(7) Within 5 days of determining that either of your action levels in paragraph (c)(4) of this section has been exceeded, you must initiate an investigative analysis to determine the underlying primary and contributing cause(s) of such exceedance and actions to be taken to reduce the mass emission rate below the applicable action level.
(i) You must complete the investigative analysis and take initial steps to bring the mass emission rate below the action level no later than 5 days after determining there is an exceedance of the action level in paragraph (c)(4)(i)(B) or (c)(4)(ii)(B) of this section.
(ii) You must complete the investigative analysis and take initial steps to bring the mass emission rate below the action level no later than 30 days after determining there is an exceedance of the action level in paragraph (c)(4)(i)(A) or (c)(4)(ii)(A) of this section.
(8) You must develop a mass emission rate reduction plan if you meet any of the criteria in paragraphs (c)(8)(i) through (iii) of this section. The plan must describe the action(s) completed to date to reduce the mass emission rate below the action level, additional measures that you propose to employ to reduce methane emissions below the action level, and a schedule for completion of these measures. You must submit the plan to the Administrator within 60 days of initially determining there is an exceedance of an action level in paragraph (c)(4) of this section.
(i) If, upon completion of the initial actions required under paragraph (c)(7) of this section, the average mass emission rate for the following 30-day period is not below the applicable action level in paragraph (c)(4)(i)(A) or (c)(4)(ii)(A) of this section. The beginning of the 30-day period starts on the calendar day following completion of the initial actions in paragraph (c)(7) of this section.
(ii) If, upon completion of the initial actions required under paragraph (c)(6) of this section, the average mass emission rate for the following 24-hour period is not below the applicable action level in paragraph (c)(4)(i)(B) or (c)(4)(ii)(B) of this section. The average mass emission rate will be the mass emission rate calculated according to paragraph (c)(6)(i) of this section for the calendar day following completion of the initial corrective actions in paragraph (c)(7) of this section.
(iii) All actions needed to reduce the average mass emission rate below the action level require more than 30 days to implement.
(9) You must maintain the records as specified in § 60.5420c(c)(3) through (c)(6), (c)(13) and (c)(14), and § 60.5424c(e). You must submit the reports as specified in § 60.5420c(b)(1), (b)(3) through (9) and § 60.5424c.