40 C.F.R. §§ 49.4169–49.4184

§49.4169. Introduction.

40 C.F.R. § 49.4169

(a)

What is the purpose of §§ 49.4169 through 49.4184? Sections 49.4169 through 49.4184 establish legally and practicably enforceable requirements for oil and natural gas sources on Indian country lands within the Uintah and Ouray Indian Reservation (U&O Reservation) to address ozone air quality. Section 49.4170 establishes provisions for delegation of authority to allow the Ute Indian Tribe to assist the EPA with administration of this Federal Implementation Plan (U&O FIP). Section 49.4171 contains general provisions and definitions applicable to oil and natural gas sources. Sections 49.4173 through 49.4184 establish legally and practicably enforceable requirements to control and reduce VOC emissions from oil and natural gas well production and storage operations, natural gas processing, and gathering and boosting operations at oil and natural gas sources that are located on Indian country lands within the U&O Reservation.

(b)

Am I subject to §§ 49.4169 through 49.4184? Sections 49.4169 through 49.4184, as appropriate, apply to each owner or operator of an oil and natural gas source (as defined at 40 CFR 49.102) located on Indian country lands within the U&O Reservation that has equipment or activities that meet the applicability thresholds specified in each section. Generally, the equipment and activities at oil and natural gas sources that are already subject to and in compliance with VOC emission control requirements under another EPA standard or other federally enforceable requirement, as specified in each appropriate subsection later, are considered to be in compliance with the requirements to control VOC emissions from that same equipment under this U&O FIP.

(c)

When must I comply with §§ 49.4169 through 49.4184? For oil and natural gas sources that commence construction before February 6, 2023, compliance with §§ 49.4169 through 49.4171 and §§ 49.4173 through 49.4184, as applicable, is required no later than February 6, 2024. You may submit a written request to the EPA for an extension of the compliance date for existing sources. The extension request must be submitted to the EPA at least 60 days before the compliance deadline, must identify the specific provision(s) for which you seek an extension, must include an alternative compliance deadline(s), and must provide the rationale for the requested extension with supporting information explaining how you will effectively meet all applicable requirements after the requested alternative compliance deadline. Any decision to approve or deny a request, including the length of time of an approved request, will be based on the merits of case-specific circumstances. For oil and natural gas sources that commence construction on or after February 6, 2023, compliance with §§ 49.4169 through 49.4171 and §§ 49.4173 through 49.4184, as applicable, is required upon startup.

Notes, amendments, and revision history

Source

Source: 87 FR 75376, Dec. 8, 2022, unless otherwise noted.

Authority

Authority: 42 U.S.C. 7401, et seq.

Source

Source: 63 FR 7271, Feb. 12, 1998, unless otherwise noted.

§49.4170. Delegation of authority of administration to the Tribe.

40 C.F.R. § 49.4170

(a)

What is the purpose of this section? The purpose of this section is to establish the process by which the Regional Administrator may delegate to the Ute Indian Tribe the authority to assist the EPA with administration of this U&O FIP. This section provides for administrative delegation and does not affect the eligibility criteria under § 49.6 for treatment in the same manner as a state.

(b)

How does the Ute Indian Tribe request delegation? To be delegated authority to assist the EPA with administration of this U&O FIP, the authorized representative of the Ute Indian Tribe must submit a written request to the Regional Administrator that:

(1)

Identifies the specific provisions for which delegation is requested;

(2)

Includes a statement by the Ute Indian Tribe's legal counsel (or equivalent official) with the following information:

(i)

A statement that the Ute Indian Tribe is an Indian tribe recognized by the Secretary of the Interior;

(ii)

A descriptive statement that meets the requirements of § 49.7(a)(2) and demonstrates that the Ute Indian Tribe is currently carrying out substantial governmental duties and powers over a defined area;

(iii)

A description of the laws of the Ute Indian Tribe that provide adequate authority to carry out the aspects of the rule for which delegation is requested; and

(3)

Demonstrates that the Ute Indian Tribe has, or will have, adequate resources to carry out the aspects of the rule for which delegation is requested.

(c)

How is the delegation of administration accomplished?

(1)

A Delegation of Authority Agreement setting forth the terms and conditions of the delegation and specifying the provisions of this rule that the Ute Indian Tribe will be authorized to implement on behalf of the EPA will be entered into by the Regional Administrator and the Ute Indian Tribe. The Agreement will become effective on the date that both the Regional Administrator and the authorized representative of the Ute Indian Tribe have signed the Agreement. Once the delegation becomes effective, the Ute Indian Tribe will be responsible, to the extent specified in the Agreement, for assisting the EPA with administration of the FIP and will act as the Regional Administrator as that term is used in these regulations. Any Delegation of Authority Agreement will clarify the circumstances in which the term “Regional Administrator” found throughout the FIP is to remain the EPA Regional Administrator and when it is intended to refer to the “Ute Indian Tribe,” instead.

(2)

A Delegation of Authority Agreement may be modified, amended, or revoked, in part or in whole, by the Regional Administrator after consultation with the Ute Indian Tribe.

(d)

How will any Delegation of Authority Agreement be publicized? The Agency will publish a document in the Federal Register informing the public of any Delegation of Authority Agreement with the Ute Indian Tribe to assist the EPA with administration of all or a portion of the FIP and identifying such delegation in the FIP. The EPA will also publish an announcement of the Delegation of Authority Agreement in local newspapers.

Notes, amendments, and revision history

Source

Source: 87 FR 75376, Dec. 8, 2022, unless otherwise noted.

Authority

Authority: 42 U.S.C. 7401, et seq.

Source

Source: 63 FR 7271, Feb. 12, 1998, unless otherwise noted.

§49.4171. General provisions.

40 C.F.R. § 49.4171

(a)

At all times, including periods of startup, shutdown, and malfunction, each owner or operator must, to the extent practicable, design, operate, and maintain all equipment used for crude oil, condensate, intermediate hydrocarbon liquid, or produced water, and gas collection, storage, processing, and handling operations covered under §§ 49.4171 and 49.4173 through 49.4184, regardless of emissions rate and including associated air pollution control equipment, in a manner that is consistent with good air pollution control practices and that minimizes leakage of VOC emissions to the atmosphere. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Administrator, including monitoring results, review of operating and maintenance procedures, and inspection of the source.

(b)

Definitions. As used in §§ 49.4169 through 49.4184, all terms not defined have the meaning given them in the Act, in 40 CFR parts 60 and 63, in the Prevention of Significant Deterioration regulations at 40 CFR 52.21, in the Federal Minor New Source Review Program in Indian Country at § 49.151, or in the Federal Implementation Plan for Managing Air Emissions from True Minor Sources in Indian Country in the Oil and Natural Gas Production and Natural Gas Processing Segments of the Oil and Natural Gas Sector at § 49.102. The following terms are defined here:

Bottom filling means the filling of a storage vessel through an inlet at or near the bottom of the storage vessel designed to have the opening covered by the liquid after the pipe normally used to withdraw liquid can no longer withdraw any liquid.

Condensate means hydrocarbon liquid separated from produced natural gas that condenses due to changes in temperature, pressure, or both, and that remains liquid at standard conditions.

Crude oil means hydrocarbon liquids that are separated from well-extracted reservoir fluids during oil and natural gas production operations, and that are stored or injected to pipelines as a saleable product. Condensate is not considered crude oil.

Electronically controlled automatic ignition device means an electronic device which generates sparks across an electrode and reaches into a combustible gas stream traveling up a flare stack or entering an enclosed combustor, at the point of the pilot tip, equipped with a temperature monitor that signals the device to attempt to re-light an extinguished pilot flame.

Enclosed combustor means a thermal oxidation system with an enclosed combustion chamber that maintains a limited constant temperature by controlling fuel and combustion air.

Flare means a thermal oxidation system using an open (without enclosure) flame that is designed and operated in accordance with the requirements of 40 CFR 60.18(b). An enclosed combustor is not considered a flare. A combustion device is not considered a flare when installed horizontally or vertically within an open pit and used to combust produced natural gas during initial well completion or temporarily during emergencies when enclosed combustors or flares installed at a source are not operational or injection of recovered produced natural gas is unavailable.

Flashing losses means natural gas emissions resulting from the presence of dissolved natural gas in the crude oil, condensate, intermediate hydrocarbon liquids or produced water, which are under high pressure that occurs as the liquids are transferred to storage vessels that are at atmospheric pressure.

Fugitive emissions component means any component that has the potential to emit fugitive emissions of VOC at an oil and natural gas source, such as valves, connectors, pressure relief devices, open-ended lines, flanges, covers and closed vent systems not subject to § 49.4176, thief hatches or other openings on a controlled storage vessel not subject to § 49.4173, compressors, instruments, and meters. Devices that vent as part of normal operations, such as natural gas-driven pneumatic controllers or natural gas-driven pneumatic pumps, are not fugitive emissions components, insofar as the natural gas discharged from the device's vent is not considered a fugitive emission. Emissions originating from locations other than the device's vent, such as the thief hatch on a controlled storage vessel, would be considered fugitive emissions.

Glycol dehydration unit process vent emissions means VOC-containing emissions from the glycol dehydration unit regenerator or still vent and the vent from the dehydration unit flash tank (if present).

Indian country is defined at 18 U.S.C. 1151 and means.

(i)

All land within the limits of any Indian reservation under the jurisdiction of the United States Government, notwithstanding the issuance of any patent, and, including rights-of-way running through the reservation,

(ii)

All dependent Indian communities within the borders of the United States whether within the original or subsequently acquired territory thereof, and whether within or without the limits of a state, and

(iii)

All Indian allotments, the Indian titles to which have not been extinguished, including rights-of-way running through the same.

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

Malfunction alarm and remote notification system means a system connected to an electronically controlled automatic ignition device that sends an alarm through a remote notification system to an owner or operator's central control center, if an attempt to relight the pilot flame is unsuccessful.

Pneumatic controller means a natural gas-driven pneumatic controller as defined at 40 CFR 60.5430 and 60.5430a.

Pneumatic pump means a natural gas-driven diaphragm pump as defined at 40 CFR 60.5430a.

Pneumatic pump emissions means the VOC-containing emissions from pneumatic pumps.

Produced natural gas means natural gas that is separated from extracted reservoir fluids during oil and natural gas production operations.

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.

Regional Administrator means the Regional Administrator of EPA Region 8 or an authorized representative of the Regional Administrator of EPA Region 8, except to the extent otherwise specifically specified in a Delegation of Authority Agreement between the Regional Administrator and the Ute Indian Tribe.

Repaired means, for the purposes of fugitive emissions components, that fugitive emissions components are adjusted, replaced, or otherwise altered in order to eliminate fugitive emissions as defined in § 49.4178(d)(1)(iii), and subsequently monitored as specified in § 49.4178(d)(1)(ii), and that it is verified that emissions from the fugitive emissions components are below the applicable fugitive emissions definition.

Standing and breathing losses means VOC emissions from fixed-roof storage vessels as a result of evaporative losses during storage.

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 non-earthen 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 will not be considered a storage vessel if it has been removed from service in accordance with the requirements of § 49.4173(a)(3), until that tank or other vessel has been returned to service. For the purposes of this subpart, the following are not considered storage vessels:

(i)

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 § 49.4183(a)(1)(iv), showing that the vessel has been located at a site for less than 180 consecutive days, the vessel is considered to be a storage vessel from the date it was first located at the site. This exclusion does not apply to a well completion vessel as described above.

(ii)

Process vessels such as surge control vessels, bottoms receivers, and knockout vessels.

(iii)

Pressure vessels designed to operate in excess of 204.9 kilopascals and without emissions to the atmosphere.

Submerged fill pipe means any fill pipe with a discharge opening that is entirely submerged when the liquid level is six inches above the bottom of the storage vessel and the pipe normally used to withdraw liquid from the storage vessel can no longer withdraw any liquid.

Supervisory Control and Data Acquisition (SCADA) system generally refers to industrial control computer systems that monitor and control industrial infrastructure or source-based processes.

Unsafe to repair means (in the context of fugitive emissions monitoring) that operator personnel would be exposed to an imminent or potential danger as a consequence of the attempt to repair the leak during normal operation of the source.

Visible smoke emissions means air pollution generated by thermal oxidation in a flare or enclosed combustor and occurring immediately downstream of the flame present in those units. Visible smoke occurring within, but not downstream of, the flame, does not constitute visible smoke emissions.

Working losses means natural gas emissions from fixed roof storage vessels resulting from evaporative losses during filling and emptying operations.

Notes, amendments, and revision history

Source

Source: 87 FR 75376, Dec. 8, 2022, unless otherwise noted.

Authority

Authority: 42 U.S.C. 7401, et seq.

Source

Source: 63 FR 7271, Feb. 12, 1998, unless otherwise noted.

§49.4172. Emissions inventory.

40 C.F.R. § 49.4172

(a)

Applicability. The emissions inventory requirements of this section apply to each oil and natural gas source, as identified in § 49.4169(b), that has actual emissions of any pollutant identified in paragraph (c) of this section greater than or equal to one ton in any consecutive 12-month period.

(b)

Each oil and natural gas source must submit an inventory for every third year, beginning with the 2023 calendar year, for all emission units at a source.

(c)

The inventory must include the total emissions for PM10, PM2.5, oxides of sulfur, nitrogen oxides, carbon monoxide, and volatile organic compounds, as defined at 40 CFR 51.50, for each emissions unit at the source. Emissions for each emissions unit at the source must be calculated using the emissions unit's actual operating hours, appropriate emissions rates, the use of performance test results where applicable, product rates and types of materials processed, stored, or combusted during the calendar year of the reporting period.

(d)

The inventory must include the type and efficiency, for each pollutant controlled, of any air pollution control equipment present at the reporting source. The detail of the emissions inventory must be consistent with the detail and data elements required by 40 CFR part 51, subpart A.

(e)

The inventory must be submitted to the EPA no later than April 15th of the year following each inventory year.

(f)

The inventory must be submitted in an electronic format specific to this source category, as instructed on the EPA Region 8 website at https://www.epa.gov/air-quality-implementation-plans/approved-air-quality-implementation-plans-region-8.

Notes, amendments, and revision history

Source

Source: 87 FR 75376, Dec. 8, 2022, unless otherwise noted.

Authority

Authority: 42 U.S.C. 7401, et seq.

Source

Source: 63 FR 7271, Feb. 12, 1998, unless otherwise noted.

§49.4173. VOC emissions control requirements for storage vessels.

40 C.F.R. § 49.4173

(a)

Applicability. The VOC emissions control requirements of this section apply to storage vessels at an oil and natural gas source (as specified in § 49.4169(b)) as follows:

(1)

For oil and natural gas sources that began operations before February 6, 2023, the VOC emissions control requirements of this section apply when the source-wide potential for VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps is equal to or greater than 4 tpy, as determined according to this section. The potential for VOC emissions must be calculated using a generally accepted model or calculation methodology, based on the maximum average daily throughput determined for a 30-day period of production during the 12 months before the compliance deadline for the affected source under this rule. The determination may take into account requirements under a legally and practicably enforceable limit in an operating permit or other federally enforceable requirement. You must reevaluate the source-wide VOC emissions from the collection of all storage vessels, glycol dehydrators and pneumatic pumps for each modification to an existing source; or

(2)

For oil and natural gas sources that began operations on or after February 6, 2023, the VOC emissions control requirements of this section apply upon startup of operation.

(3)

Modification to an oil and natural gas source requires a re-evaluation of the source-wide VOC emissions from the collection of all storage vessels, glycol dehydrators and pneumatic pumps. Adding production from a new well or increasing production at an existing well is considered a modification of a well site. Increasing maximum throughput at a tank battery, compressor station or natural gas processing plant is considered a modification.

(b)

Exemptions.

(1)

This section does not apply to storage vessels located at an oil and natural gas source that are subject to the emissions control requirements for storage vessels in 40 CFR part 60, subparts OOOO or OOOOa, or 40 CFR part 63, subpart HH.

(2)

This section does not apply to an emergency storage vessel located at an oil and natural gas source, if it meets the following requirements:

(i)

The emergency storage vessel is not used as an active storage vessel;

(ii)

The owner or operator empties the emergency storage vessel no later than 15 days after receiving fluids;

(iii)

The emergency storage vessel is equipped with a liquid level gauge or equivalent device; and

(iv)

Records are kept of the usage of each emergency storage vessel as required in § 49.4183(a)(3), including the date the vessel received fluids, the volume of fluids received in barrels, the date the vessel was emptied, and the volume of fluids emptied in barrels.

(3)

This section does not apply to storage vessels that are removed from service. If you remove a storage vessel from service, you must comply with paragraphs (b)(3)(i) through (iii) of this section.

(i)

For a storage vessel to be removed from service, you must comply with the requirements of paragraphs (b)(3)(i)(A) and (B) of this section.

(A)

You must completely empty and degas the storage vessel, such that the storage vessel no longer contains crude oil, condensate, intermediate hydrocarbon liquids or produced water. 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.

(B)

You must keep records as required in § 49.4183(a)(4), identifying each storage vessel removed from service and the date of its removal from service.

(ii)

If a storage vessel identified in paragraph (b)(3)(i)(B) of this section is returned to service, you must determine its applicability as provided in paragraph (a) of this section, and you must keep records as required in § 49.4183(a)(4), identifying the storage vessel and the date of its return to service.

(c)

VOC emission control requirements. For each storage vessel, you must comply with the VOC emissions control requirements of paragraph (c)(1) or (c)(2) of this section.

(1)

You must reduce VOC emissions from each storage vessel by at least 95.0 percent on a continuous basis according to paragraph (c)(1)(i) or (ii) of this section. You must equip each storage vessel with a cover that meets the conditions specified in § 49.4176(c), and must route all flashing, working, standing and breathing losses from the storage vessels through a closed-vent system that meets the conditions specified in § 49.4176(d) to:

(i)

An operating system designed to recover 100 percent of the emissions and recycle them for use in a process unit or incorporate them into a product; or

(ii)

An enclosed combustor or flare that is designed to reduce the mass content of VOC in the natural gas emissions vented to the device by at least 95.0 percent and that is operated as specified in § 49.4177;

(2)

You must maintain the source-wide uncontrolled actual VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps at an oil and natural gas source at less than 4 tpy. Before using the uncontrolled actual VOC emission rate for compliance purposes, you must demonstrate that the uncontrolled actual VOC emissions have remained at less than 4 tpy, as determined monthly for 12 consecutive months. After such demonstration, you must determine the uncontrolled actual VOC emission rate each month. The uncontrolled actual VOC emissions must be calculated using a generally accepted model or calculation methodology. Monthly calculations must be based on the average throughput of the source for the month. Monthly calculations must be separated by at least 14 days. You must comply with paragraph (c)(1) of this section within 30 days of the monthly emissions determination required in this section if the determination indicates that VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps at your oil and natural gas source increased to 4 tpy or greater.

(3)

Except as provided in paragraph (c)(4) of this section, if you use a control device to reduce emissions from your storage vessels, you must equip each storage vessel with a cover that meets the requirements of § 49.4176(c).

(4)

If you use a floating roof to reduce emissions, you must meet the requirements of § 60.112b(a)(1) or (2) and the relevant monitoring, inspection, recordkeeping, and reporting requirements in 40 CFR part 60, subpart Kb.

(5)

After a minimum of 12 consecutive months of operation at a source that begins operation on or after February 6, 2023, controls may be removed if the source-wide uncontrolled actual VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps has been maintained at a rate less than 4 tpy, as determined according to paragraph (c)(2) of this section.

Notes, amendments, and revision history

Source

Source: 87 FR 75376, Dec. 8, 2022, unless otherwise noted.

Authority

Authority: 42 U.S.C. 7401, et seq.

Source

Source: 63 FR 7271, Feb. 12, 1998, unless otherwise noted.

§49.4174. VOC emissions control requirements for dehydrators.

40 C.F.R. § 49.4174

(a)

Applicability. The VOC emissions control requirements of this section apply to each glycol dehydration unit located at an oil and natural gas source as identified in § 49.4169(b) where the source-wide potential for VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps is equal to or greater than 4 tpy, as determined according to § 49.4173. You must reevaluate the source-wide VOC emissions from the collection of all storage vessels, glycol dehydrators and pneumatic pumps for each modification to an existing source, as described in § 49.4173(a)(3). Applicability for glycol dehydrators that began operation before February 6, 2023 must be determined using uncontrolled actual emissions. Applicability for glycol dehydrators that began operation on or after February 6, 2023 must be determined using potential to emit.

(b)

Exemptions. This section does not apply to glycol dehydration units subject to the emissions control requirements for glycol dehydration unit process vents in 40 CFR part 63, subpart HH.

(c)

VOC emissions control requirements. For each glycol dehydration unit, you must comply with the VOC emissions control requirements of paragraphs (c)(1) or (2) of this section.

(1)

You must reduce VOC emissions from each glycol dehydration unit process vent by at least 95.0 percent on a continuous basis according to paragraphs (c)(1)(i) and (ii) of this section. You must route all glycol dehydration unit process vent emissions through a closed-vent system that meets the conditions specified in § 49.4176(d) to:

(i)

An operating system designed to recover 100 percent of the emissions and recycle them for use in a process unit or incorporate them into a product; or

(ii)

An enclosed combustor or flare designed to reduce the mass content of VOC in the emissions vented to the device by at least 95.0 percent and operated as specified in § 49.4177; or

(2)

You must maintain the source-wide uncontrolled actual VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps at an oil and natural gas source at less than 4 tpy for 12 consecutive months in accordance with the procedures specified in § 49.4173(c)(2).

Notes, amendments, and revision history

Source

Source: 87 FR 75376, Dec. 8, 2022, unless otherwise noted.

Authority

Authority: 42 U.S.C. 7401, et seq.

Source

Source: 63 FR 7271, Feb. 12, 1998, unless otherwise noted.

§49.4175. VOC emissions control requirements for pneumatic pumps.

40 C.F.R. § 49.4175

(a)

Applicability. The requirements of this section apply to each pneumatic pump located at an oil and natural gas source as identified in § 49.4169(b) where the source-wide potential for VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps is equal to or greater than 4 tpy, as determined according to § 49.4173. You must reevaluate the source-wide VOC emissions from the collection of all storage vessels, glycol dehydrators and pneumatic pumps for each modification to an existing source, as described in § 49.4173(a)(3). Applicability for pneumatic pumps that began operation before February 6, 2023 must be determined using uncontrolled actual emissions. Applicability for pneumatic pumps that began operation on or after February 6, 2023 must be determined using potential to emit.

(b)

Exemptions. This section does not apply to pneumatic pumps subject to the emissions control requirements for pneumatic pumps in 40 CFR part 60, subpart OOOOa.

(c)

VOC Emission Control Requirements. For each pneumatic pump, you must comply with the VOC emissions control requirements of paragraph (c)(1) or (2) of this section.

(1)

You must reduce VOC emissions from each pneumatic pump by at least 95.0 percent on a continuous basis according to paragraph (c)(1)(i) or (ii) of this section. You must route all pneumatic pump emissions through a closed-vent system that meets the conditions specified in § 49.4176(d) to:

(i)

An operating system designed to recover 100 percent of the emissions and recycle them for use in a process unit or incorporate them into a product; or

(ii)

An enclosed combustor or flare designed to reduce the mass content of VOC in the emissions vented to the device by at least 95.0 percent and operated as specified in § 49.4177; or

(2)

You must maintain the source-wide uncontrolled actual VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps at an oil and natural gas source at less than 4 tpy for any 12 consecutive months in accordance with the procedures specified in § 49.4173(c)(2).

Notes, amendments, and revision history

Source

Source: 87 FR 75376, Dec. 8, 2022, unless otherwise noted.

Authority

Authority: 42 U.S.C. 7401, et seq.

Source

Source: 63 FR 7271, Feb. 12, 1998, unless otherwise noted.

§49.4176. VOC emissions control requirements for covers and closed-vent systems.

40 C.F.R. § 49.4176

(a)

Applicability. The VOC emissions control requirements in this section apply to each cover on a storage vessel that is subject to § 49.4173, and to each closed-vent system that is used to convey VOC emissions from the collection of all storage vessels, glycol dehydration units, or pneumatic pumps (to a vapor recovery system or control device) that are subject to §§ 49.4173 through 49.4175.

(b)

Exemptions. This section does not apply to covers and closed-vent systems that are subject to the requirements for covers and closed-vent systems in 40 CFR part 60, subparts OOOO or OOOOa, or 40 CFR part 63, subpart HH.

(c)

Covers. Each owner or operator must equip all openings on each storage vessel with a cover to ensure that all flashing, working, standing and breathing loss emissions are routed through a closed-vent system to a vapor recovery system, an enclosed combustor, or a flare.

(1)

Each cover and all openings on the cover (e.g., access hatches, sampling ports, pressure relief valves (PRV), and gauge wells) must form a continuous impermeable barrier over the entire surface area of the crude oil, condensate, intermediate hydrocarbon liquids, or produced water in the storage vessel.

(2)

Each cover opening must be secured in a closed, sealed position (e.g., covered by a gasketed lid or cap) whenever material is in the unit on which the cover is installed except when it is necessary to use an opening as follows:

(i)

To add fluids to, or remove fluids from the unit (this includes openings necessary to equalize or balance the internal pressure of the unit following changes in the level of the material in the unit);

(ii)

To inspect or sample the fluids in the unit; or

(iii)

To inspect, maintain, repair, or replace equipment located inside the unit.

(3)

Each thief hatch cover must be weighted and properly seated to ensure that flashing, working, standing, and breathing loss emissions are routed through the closed-vent system to the vapor recovery system, the enclosed combustor, or the flare under normal operating conditions.

(4)

Each PRV must be set to release at a pressure that will ensure that flashing, working, standing, and breathing loss emissions are routed through the closed-vent system to the vapor recovery system, the enclosed combustor, or the flare under normal operating conditions.

(d)

Closed-vent systems. Each owner or operator must meet the following requirements for closed-vent systems:

(1)

Each closed-vent system must route all captured storage vessel emissions from flashing, working, standing, and breathing losses; glycol dehydration unit process vent emissions; and pneumatic pump emissions from the oil and natural gas source to a gathering pipeline system for sale, use in a process unit, incorporation into a product, or other beneficial purpose, or to a VOC emission control device, as specified in §§ 49.4173 through 49.4175.

(2)

All vent lines, connections, fittings, valves, relief valves, and any other appurtenances employed to collect or contain captured storage vessel emissions from flashing, working, standing, and breathing losses; glycol dehydration unit process vent emissions; or pneumatic pump emissions; or to transport such emissions to a gathering pipeline system for sale, use in a process unit, incorporation into a product, or other beneficial purpose, or to a VOC emission control device, as specified in §§ 49.4173 through 49.4175, must be maintained and operated properly at all times.

(3)

Each closed-vent system must be designed to operate with no detectable emissions, as demonstrated by the closed-vent system monitoring requirements in § 49.4182(c).

(4)

If any closed-vent system contains one or more bypass devices that could be used to divert all or a portion of the captured storage vessel flashing, working, standing, and breathing losses; glycol dehydration unit process vent emissions; or pneumatic pump emissions from entering a gathering pipeline system for sale, use in a process unit, incorporation into a product, or other beneficial purpose, or from being transferred to the VOC emissions control device, the owner or operator must meet one of the requirements in paragraphs (d)(4)(i) or (ii) of this section for each bypass device. Low leg drains, high point bleeds, analyzer vents, open-ended valves or lines, and safety devices are not subject to the requirements applicable to bypass devices.

(i)

At the inlet to a bypass device the owner or operator must properly install, calibrate, maintain, and operate a flow indicator that is capable of taking continuous readings and sounding an alarm when the bypass device is open such that emissions are being, or could be, diverted away from a gathering pipeline system for sale, use in a process unit, incorporation into a product, or other beneficial purpose, or the VOC emission control device and into the atmosphere; or

(ii)

The owner or operator must secure the bypass device valve installed at the inlet to the bypass device in the non-diverting position using a car-seal or a lock-and-key type configuration.

Notes, amendments, and revision history

Source

Source: 87 FR 75376, Dec. 8, 2022, unless otherwise noted.

Authority

Authority: 42 U.S.C. 7401, et seq.

Source

Source: 63 FR 7271, Feb. 12, 1998, unless otherwise noted.

§49.4177. VOC emissions control devices.

40 C.F.R. § 49.4177

(a)

Applicability. The requirements in this section apply to all flares and enclosed combustors used to control VOC emissions at an oil and natural gas source, as identified in § 49.4169(b), in order to meet the requirements specified in §§ 49.4173 through 49.4176, as applicable.

(b)

Exemptions. This section does not apply to VOC emission control devices that are subject to the requirements for control devices used to comply with the emissions standards in 40 CFR part 60, subparts OOOO or OOOOa; or 40 CFR part 63, subpart HH.

(c)

Enclosed combustors and flares. Each owner or operator must meet the following requirements for enclosed combustors and flares:

(1)

For each enclosed combustor or flare, the owner or operator must follow the manufacturer's written operating instructions, procedures, and maintenance schedule to ensure good air pollution control practices for minimizing emissions;

(2)

The owner or operator must ensure that each enclosed combustor or flare is designed to have sufficient capacity to reduce the mass content of VOC in the captured emissions routed to it by at least 95.0 percent for the minimum and maximum natural gas volumetric flow rate and BTU content routed to the device;

(3)

Each enclosed combustor or flare must be operated to reduce the mass content of VOC in the captured emissions routed to it by continuously meeting at least 95.0 percent VOC control efficiency;

(4)

The owner or operator must ensure that each flare is designed and operated in accordance with the requirements of 40 CFR 60.18(b) for such flares;

(5)

The owner or operator must ensure that each enclosed combustor is:

(i)

A model that is—

(A)

Demonstrated by a manufacturer to meet the VOC control efficiency requirements of §§ 49.4173 through 49.4176 using EPA-approved performance test procedures specified in 40 CFR 60.5413; or

(B)

Demonstrated by the owner or operator to meet the VOC control efficiency requirements of §§ 49.4173 through 49.4176 according to the procedures and schedule specified in § 49.4182(d)(1);

(ii)

Operated properly at all times that captured emissions are routed to it;

(iii)

Operated with a liquid knock-out system to collect any condensable vapors (to prevent liquids from going through the control device);

(iv)

Equipped and operated with a flash-back flame arrestor;

(v)

Equipped and operated with one of the following—

(A)

A continuous burning pilot; or

(B)

An operational electronically controlled automatic ignition device;

(vi)

Equipped with a monitoring system for continuous measuring and recording of the parameters that indicate proper operation of each enclosed combustor or flare, including each continuous burning pilot flame or electronically controlled automatic ignition device, to monitor and document proper operation of the enclosed combustor or flare. Examples of such continuous monitoring systems may include a thermocouple and a chart recorder, data logger or similar device, or connection to a SCADA system;

(vii)

Maintained in a leak-free condition; and

(viii)

Operated with no visible smoke emissions.

(d)

Other control devices. Upon prior written approval by the EPA, the owner or operator may use control devices other than those listed above that are determined by the EPA to be capable of reducing the mass content of VOC in the natural gas routed to it by at least 95.0 percent, provided that:

(1)

In operating such control devices, the owner or operator must follow the manufacturer's written operating instructions, procedures and maintenance schedule to ensure good air pollution control practices for minimizing emissions; and

(2)

The owner or operator must ensure there is sufficient capacity to reduce the mass content of VOC in the produced natural gas and natural gas emissions routed to such other control devices by at least 95.0 percent for the minimum and maximum natural gas volumetric flow rate and BTU content routed to each device.

(3)

The owner or operator must operate such a control device to reduce the mass content of VOC in the produced natural gas and natural gas emissions routed to it by at least 95.0 percent.

Notes, amendments, and revision history

Source

Source: 87 FR 75376, Dec. 8, 2022, unless otherwise noted.

Authority

Authority: 42 U.S.C. 7401, et seq.

Source

Source: 63 FR 7271, Feb. 12, 1998, unless otherwise noted.

§49.4178. VOC emissions control requirements for fugitive emissions.

40 C.F.R. § 49.4178

(a)

Applicability. The requirements of this section apply to all owners or operators of the collection of fugitive emissions components, as defined in § 49.4171, located at any oil and natural gas source, as identified in § 49.4169(b), except that this section does not apply to owners or operators of the collection of fugitive emissions components at an oil and natural gas source that is subject to the fugitive emissions monitoring requirements in 40 CFR part 60, subpart OOOOa.

(b)

Owners or operators of the collection of fugitive emissions components must comply with paragraph (d) of this section if either of the following is true:

(1)

The collection of fugitive emissions components is located at an oil and natural gas source that is required to control VOC emissions according to §§ 49.4173 through 49.4177 of this section (i.e., the source-wide potential for VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps is equal to or greater than 4 tpy, as determined according to § 49.4173(a)(1)); or

(2)

The collection of fugitive emissions components is located at a well site, as defined in 40 CFR 60.5430a, that at any time has total production greater than 15 barrels of oil equivalent (boe) per day based on a rolling 12-month average.

(c)

Owners or operators of the collection of fugitive emissions components for which neither (b)(1) nor (b)(2) is true must comply with either paragraph (c)(1) or paragraph (c)(2) of this section.

(1)

You must monitor all fugitive emissions components and repair all sources of fugitive emissions in accordance with paragraph (d) of this section. You must keep records in accordance with § 49.4183 and report in accordance with § 49.4184; or

(2)

You must maintain the total production for the well site at or below 15 boe per day based on a rolling 12-month average. You must demonstrate that the total daily oil and natural gas production from the collection of all wells producing to the well site is at or below 15 boe per day, based on a 12-month rolling average, according to the procedures in paragraph (e) of this section. You must maintain records as specified in § 49.4183(a)(11).

(d)

Monitoring requirements.

(1)

Each owner or operator must develop and implement a fugitive emissions monitoring plan to reduce emissions from fugitive emissions components at all of their oil and natural gas sources on Indian country lands within the U&O Reservation. This Reservation-wide monitoring plan must include the following elements, at a minimum:

(i)

A requirement to perform an initial monitoring of the collection of fugitive emissions components at each oil and natural gas source by February 6, 2024;

(ii)

A requirement to perform subsequent monitoring of the collection of fugitive emissions components at each oil and natural gas source once every 6 months after the initial monitoring survey, with consecutive monitoring surveys conducted at least 4 months apart and no more than 7 months apart.

(iii)

A description of the technique used to identify leaking fugitive emission components, which must be limited to:

(A)

Onsite EPA Reference Method 21, 40 CFR part 60, appendix A, where an analyzer reading of 500 parts per million volume (ppmv) VOC or greater is considered a leak in need of repair;

(B)

Onsite optical gas imaging instruments, as defined in 40 CFR 60.18(g)(4), where any visible emissions are considered a leak in need of repair, unless the owner or operator evaluates the leak with an analyzer meeting EPA Reference Method 21 at 40 CFR part 60, appendix A, and the concentration is less than 500 ppmv. The optical gas imaging instrument must be capable of meeting the optical gas imaging equipment requirements specified in 40 CFR part 60, subpart OOOOa; or

(C)

Another method approved by the Administrator to demonstrate compliance with the fugitive emissions monitoring requirements. To be approved, you must demonstrate that the alternative method achieves emissions reductions that equal or exceed those that would result from the application of either Method 21 or optical gas imaging instruments. Approval of an alternative method will be subject to public notice and comment.

(iv)

The manufacturer and model number of any fugitive emissions monitoring device to be used;

(v)

Procedures and timeframes for identifying and repairing components from which leaks are detected, including:

(A)

A requirement to repair any leaks identified from components that are safe to repair and do not require source shutdown as soon as practicable, but no later than 30 calendar days after discovering the leak;

(B)

Timeframes for inspecting and repairing leaking components that are difficult-to-monitor, unsafe-to-monitor, or require source shutdown, to be no later than the next required monitoring event, as noted in paragraphs (c)(1)(v)(B)(1) through (3) of this section:

(1) If using Method 21, 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 and must meet the specifications in paragraphs (c)(1)(v)(B)(1)(i) through (iv) of this section:

(i) For all fugitive emissions components designated difficult-to-monitor, a written plan must be developed and incorporated into the fugitive emissions monitoring plan.

(ii) The plan must include the identification and location of each fugitive emissions component designated 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 and a schedule for repairing such fugitive emissions components according to paragraph (c)(1)(v)(B)(3) of this section;

(2) Fugitive emissions components that cannot be monitored because monitoring personnel would be exposed to an immediate danger while conducting a monitoring survey may be designated as unsafe-to-monitor and must meet the specification in paragraphs (c)(1)(v)(B)(2)(i) through (iv) of this section:

(i) A written plan must be developed for all of the fugitive emissions components designated unsafe-to-monitor and incorporated into the fugitive emissions monitoring plan;

(ii) The plan must include the identification and location of each fugitive emissions component designated 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 unsafe-to-monitor fugitive emissions components as frequently as practicable during safe to inspect times and for repairing such fugitive emissions components according to paragraph (c)(1)(v)(B)(3) of this section;

(3) If the repair or replacement of a fugitive emissions component designated difficult-to-monitor or unsafe-to-monitor 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 or replacement must be completed during the next scheduled compressor station shutdown, well shutdown, or well shut-in; after a planned vent blowdown; or within 2 years, whichever is earlier; and

(C)

Procedures for verifying leaking component repairs, no more than 30 calendar days after repairing the leak;

(vi)

Training and experience needed before performing surveys;

(vii)

Procedures for calibration and maintenance of any fugitive emissions monitoring device to be used; and

(viii)

Standard monitoring protocols for each type of typical oil and natural gas source (e.g., well site, tank battery, compressor station), including a general list of component types that will be inspected and what supporting data will be recorded (e.g., wind speed, detection method device-specific operational parameters, date, time, and duration of inspection).

(2)

The owner or operator is exempt from inspecting and repairing a fugitive emissions component under any of the following circumstances:

(i)

The contacting process stream only contains glycol, amine, methanol, or produced water; or

(ii)

The component to be inspected is buried, insulated in a manner that prevents access to the components by a monitor probe or optical gas imaging device, or obstructed by equipment or piping that prevents access to the components by a monitor probe or optical gas imaging device.

(e)

Procedures for determining total well site production. The total well site production must be determined according to the following procedures:

(1)

Calculate the total average boe per day for each calendar month using—

(i)

For existing well sites, the records of production for the first 30 days after becoming subject to this section.

(ii)

For well sites that commence construction, reconstruction or modification on or after February 6, 2023, the first 30 days of production, performing the calculation within 45 days of the end of the first 30 days of production.

(2)

Determine the daily oil and natural gas production for each individual well at the well site for the month. To convert gas production to equivalent barrels of oil, divide the cubic feet of gas produced by 6,000.

(3)

Sum the daily production for each individual well at the well site to determine the total well site production and divide by the total number of days in the calendar month. This is the average daily total well site production for the month.

(4)

Use the result determined in paragraph (e)(2) of this section and average with the daily average well site production values determined for each of the preceding 11 months to calculate the rolling 12-month average of the total well site production.

Notes, amendments, and revision history

Source

Source: 87 FR 75376, Dec. 8, 2022, unless otherwise noted.

Authority

Authority: 42 U.S.C. 7401, et seq.

Source

Source: 63 FR 7271, Feb. 12, 1998, unless otherwise noted.

§49.4179. VOC emissions control requirements for tank truck loading.

40 C.F.R. § 49.4179

(a)

Applicability. The requirements in this section apply to each owner or operator who loads or permits the loading of any intermediate hydrocarbon liquid or produced water at an oil and natural gas source as identified in § 49.4169(b).

(b)

Tank truck loading requirements. Tank trucks used for transporting intermediate hydrocarbon liquid or produced water must be loaded and unloaded using measures to minimize VOC emissions. These measures must include, at a minimum, bottom filling or a submerged fill pipe, as defined in § 49.4171(b).

Notes, amendments, and revision history

Source

Source: 87 FR 75376, Dec. 8, 2022, unless otherwise noted.

Authority

Authority: 42 U.S.C. 7401, et seq.

Source

Source: 63 FR 7271, Feb. 12, 1998, unless otherwise noted.

§49.4180. VOC emissions control requirements for pneumatic controllers.

40 C.F.R. § 49.4180

(a)

Applicability. The VOC emissions control requirements in this section apply to each owner or operator of any existing pneumatic controller located at an oil and natural gas source as identified in § 49.4169(b).

(b)

Exemptions. This section does not apply to pneumatic controllers subject to and controlled in accordance with the requirements for pneumatic controllers in 40 CFR part 60, subparts OOOO or OOOOa.

(c)

Retrofit requirements. All existing pneumatic controllers must meet the standards established for pneumatic controllers that are constructed, modified, or reconstructed on or after October 15, 2013, as specified in 40 CFR part 60, subpart OOOO.

(d)

Documentation requirements. The owner or operator of any existing pneumatic controllers must meet the tagging requirements in 40 CFR 60.5390(a), except that the month and year of installation, reconstruction or modification is not required.

Notes, amendments, and revision history

Source

Source: 87 FR 75376, Dec. 8, 2022, unless otherwise noted.

Authority

Authority: 42 U.S.C. 7401, et seq.

Source

Source: 63 FR 7271, Feb. 12, 1998, unless otherwise noted.

§49.4181. Other combustion devices.

40 C.F.R. § 49.4181

(a)

Applicability. The VOC emission control requirements in this section apply to each owner or operator of any existing enclosed combustor or flare located at an oil and natural gas source as identified in § 49.4169(b) that is used to control VOC emissions, but that is not required under §§ 49.4173 through 49.4175 of this rule.

(b)

Retrofit requirements. All existing enclosed combustors and flares must be equipped with an operational electronically controlled automatic ignition device.

Notes, amendments, and revision history

Source

Source: 87 FR 75376, Dec. 8, 2022, unless otherwise noted.

Authority

Authority: 42 U.S.C. 7401, et seq.

Source

Source: 63 FR 7271, Feb. 12, 1998, unless otherwise noted.

§49.4182. Monitoring and testing requirements.

40 C.F.R. § 49.4182

(a)

Applicability. The monitoring and testing requirements in paragraphs (c) and (d) of this section apply, as appropriate, to each oil and natural gas source as identified in § 49.4169(b) with equipment or activities that are subject to §§ 49.4173 through 49.4177.

(b)

Exemptions. Paragraphs (c) and (d) of this section do not apply to any storage vessels, glycol dehydration units, pneumatic pumps, covers, or closed-vent systems, or to VOC emission control devices subject to and monitored in accordance with the monitoring requirements for such equipment and activities in 40 CFR part 60, subparts OOOO or OOOOa, or 40 CFR part 63, subpart HH.

(c)

Each owner or operator must inspect each cover and closed-vent system as specified in paragraphs (c)(1) or (2).

(1)

Conduct olfactory, visual, and auditory inspections at least once every calendar month, separated by at least 15 days between each inspection, of each cover and closed-vent system, including each bypass device, and each storage vessel thief hatch, seal, and pressure relief valve, to ensure proper condition and functioning of the equipment to identify defects that can result in air emissions according to the procedures. Examples of defects are visible cracks, holes, or gaps in the cover or piping, or between the cover and the separator wall; loose connections; liquid leaks; and broken, cracked, or otherwise damaged seals or gaskets on closure devices, caps, or other closure devices. If the storage vessel is partially or entirely buried, you must inspect only those portions of the cover that extend to or above the ground surface, and those connections that are on such portions of the cover (e.g., fill ports, access hatches, gauge wells) and can be opened to the atmosphere. The inspector should note whether there are signs of oil releases around storage vessel thief hatches, seals and pressure relief valves (e.g., staining on the storage vessel), which may indicate over-pressure events that occurred when the storage vessel was being filled. Any defects identified must be corrected or repaired within 30 days of identification.

(2)

Conduct optical gas imaging inspections of each cover and closed vent system for any visible emissions at the same frequency as the frequency for the collection of fugitive emissions components located at the oil and natural gas source, as specified in § 49.4178(d)(1).

(d)

Each owner or operator must monitor the operation of each enclosed combustor and flare to confirm proper operation and demonstrate compliance with the requirements of § 49.4177(c), as follows and as applicable:

(1)

Demonstrate compliance with the requirement of § 49.4177(c)(5)(i)(B) that each enclosed combustor must be demonstrated by the owner or operator to meet the VOC control efficiency requirements of §§ 49.4173 through 49.4176, by conducting performance tests using EPA-approved performance test methods and procedures specified in 40 CFR 60.5413 and according to the schedule specified in paragraphs (d)(1)(i) and (ii) of this section.

(i)

You must conduct an initial performance test within 180 days after the effective date of this rule for existing enclosed combustors, and within 180 days after initial startup for new enclosed combustors. You must submit the performance test results as specified in § 49.4184(a) within 60 days of completing the test.

(ii)

You must conduct periodic performance tests for all enclosed combustors required to conduct initial performance tests. You must conduct the first periodic performance test no later than 60 months after the initial performance test required in paragraph (d)(1)(i) of this section. You must conduct subsequent periodic performance tests at intervals no longer than 60 months following the previous periodic performance test or whenever you desire to establish a new operating limit. You must submit the periodic performance test results as specified in § 49.4184(a) within 60 days of completing each test.

(iii)

The owner or operator of an enclosed combustor whose model is tested under, and meets the criteria of, § 49.4177(c)(5)(i)(A) is not required to conduct performance testing.

(2)

Conduct inspections of each enclosed combustor or flare at least once every calendar month, separated by at least 15 days between each inspection, to confirm proper operation of the device, as follows:

(i)

Demonstrate that each enclosed combustor or flare is operated with no visible smoke emissions, except for periods not to exceed a total of 1 minute during any 15-minute period, by conducting a visible emissions test using section 11 of EPA Method 22 of appendix A-7 of 40 CFR part 60. The observation period must be of sufficient length to meet the requirement for determining compliance with this visible emissions standard. Devices failing the visible emissions test must follow manufacturer's repair instructions, if available, or best combustion engineering practice as outlined in the unit inspection and maintenance plan, to return the unit to compliant operation. All inspection, repair, and maintenance activities for each unit must be recorded in a maintenance and repair log and must be available for inspection. Following return to operation from maintenance or repair activity, each device must pass a Method 22 of Appendix A-7 of 40 CFR part 60 visual observation as described in this paragraph.

(ii)

Conduct visual inspections to confirm that the pilot is lit when vapors are being routed to the device and that the continuous burning pilot or electronically controlled automatic ignition device and the continuous parameter monitoring system is operating properly;

(iii)

Conduct olfactory, visual and auditory inspections of all other equipment associated with the combustion device to ensure system integrity; and

(iv)

Respond to any indication of pilot flame failure and ensure that the pilot flame is relit as soon as practically and safely possible after discovery.

(e)

Where sufficient to meet the monitoring requirements in this section, the owner or operator may use a SCADA system to monitor and record the required data.

Notes, amendments, and revision history

Source

Source: 87 FR 75376, Dec. 8, 2022, unless otherwise noted.

Authority

Authority: 42 U.S.C. 7401, et seq.

Source

Source: 63 FR 7271, Feb. 12, 1998, unless otherwise noted.

§49.4183. Recordkeeping requirements.

40 C.F.R. § 49.4183

(a)

Each owner or operator of an oil and natural gas source as identified in § 49.4169(b) must maintain the following records, as applicable:

(1)

Monthly calculations, as specified in § 49.4173(c)(2), demonstrating that the uncontrolled actual VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps at an oil and natural gas source, as identified in § 49.4169(b), have been maintained at less than 4 tpy;

(2)

Records of monthly and rolling 12-month crude oil, condensate, intermediate hydrocarbon liquids, produced water or natural gas throughput;

(3)

For each emergency storage vessel that is exempted from the control requirements of § 49.4173(b)(2), records of usage including:

(i)

The date the vessel received fluids;

(ii)

The volume of fluids received in barrels;

(iii)

The date the overflow vessel was emptied; and

(iv)

The volume of fluids emptied in barrels.

(4)

Identification of each storage vessel that is removed from service or returned to service as specified in § 49.4173(b)(3), including the date the storage vessel was removed from service or returned to service.

(5)

For storage vessels that are skid-mounted or permanently attached to something that is mobile (such as trucks, railcars, barges or ships), records indicating the number of consecutive days that the vessel is located at an oil and natural gas source. If a storage vessel is removed from an oil and natural gas source and, within 30 days, is either returned to the source or replaced by another storage vessel at the source to serve the same or similar function, then the entire period since the original storage vessel was first located at the source, including the days when the storage vessel was removed, must be added to the count of the number of consecutive days.

(6)

For each enclosed combustor or flare at an oil and natural gas source required under §§ 49.4173 through 49.4177:

(i)

Manufacturer-written, site-specific designs, operating instructions, operating procedures and maintenance schedules, including those of any operation monitoring systems;

(ii)

Date of installation;

(iii)

Records of required monitoring of operations in § 49.4182(d)(1);

(iv)

Records of any instances in which the pilot flame is not present or the monitoring equipment is not functioning in the enclosed combustor or flare, the date and times of the occurrence, the corrective actions taken, and any preventative measures adopted to prevent recurrence of the occurrence; and

(v)

Records of any visible emissions tests conducted according to § 49.4182(d)(3), including any time periods in which visible smoke emissions are observed emanating from the enclosed combustor or flare.

(7)

For each closed-vent system—

(i)

The date of installation; and

(ii)

Records of any instances in which any closed-vent system or control device was bypassed or down, the reason for each incident, its duration, and the corrective actions taken, and any preventative measures adopted to avoid such bypasses or downtimes.

(8)

Documentation of all storage vessel and closed-vent system inspections required in § 49.4182(c). All inspection records must include the following information:

(i)

The date of the inspection;

(ii)

The findings of the inspection;

(iii)

Any adjustments or repairs made as a result of the inspection, and the date of the adjustment or repair; and

(iv)

The inspector's name or identification number;

(9)

The Uinta Basin-wide fugitive emissions monitoring plan for the Indian country lands within the U&O Reservation, including all elements required by § 49.4178(d).

(10)

Documentation of each fugitive emissions inspection conducted in accordance with § 49.4178(d). All inspection records must include the following information:

(i)

The date of the inspection;

(ii)

The identification of any component that was determined to be leaking;

(iii)

The identification of any component designated difficult-to-monitor or unsafe-to-monitor that was not inspected, and the reason it was not inspected;

(iv)

The date of the first attempt to repair the leaking component;

(v)

The identification of any leaking component with a delayed repair and the reason for the delayed repair:

(A)

For unavailable parts— (1) The date of ordering a replacement component; and

(2) The date the replacement component was received; and

(B)

For a shutdown— (1) The reason the repair is technically infeasible;

(2) The date of the shutdown;

(3) The date of subsequent startup after a shutdown; and

(4) Emission estimates of the shutdown and the repair if the delay is longer than 6 months;

(vi)

The date and description of any corrective action taken, including the date the component was verified to no longer be leaking;

(vii)

The identification of each component exempt under § 49.4178(d)(2), including the type of component and a description of the qualifying exemption; and

(viii)

The inspector's name or identification number.

(11)

For each well site complying with either § 49.4178(b)(2) or § 49.4178(c)(2), you must maintain records of the rolling 12-month average daily production no later than 12 months before complying with § 49.4178(b)(2) or § 49.4178(c)(2).

(12)

For each electronically controlled automatic ignition system required under § 49.4181, records demonstrating the date of installation and manufacturer specifications; and

(13)

For each retrofitted pneumatic controller, the records required in 40 CFR 60.5420(c)(4)(i).

(b)

Each owner or operator must keep all records required by this section onsite at the source or at the location that has day-to-day operational control over the source and must make the records available to the EPA upon request.

(c)

Each owner or operator must retain all records required by this section for a period of at least 5 years from the date the record was created.

Notes, amendments, and revision history

Source

Source: 87 FR 75376, Dec. 8, 2022, unless otherwise noted.

Authority

Authority: 42 U.S.C. 7401, et seq.

Source

Source: 63 FR 7271, Feb. 12, 1998, unless otherwise noted.

§49.4184. Notification and reporting requirements.

40 C.F.R. § 49.4184

(a)

Unless otherwise specified, each owner or operator must submit any documents required under this rule to: U.S. EPA Region 8, Enforcement and Compliance Assurance Division, Air and Toxics Enforcement Branch, 8ENF-AT, 1595 Wynkoop St., Denver, CO 80202, or documents may be submitted electronically to [email protected] and/or to the EPA's Compliance and Emissions Data Reporting Interface (CEDRI). Information on CEDRI is available at https://www.epa.gov/electronic-reporting-air-emissions/cedri; CEDRI can be accessed directly through the EPA's Central Data Exchange (CDX) at https://cdx.epa.gov/. The EPA will make all the information submitted through CEDRI available to the public without further notice to you. Do not use CEDRI to submit information you claim as confidential business information (CBI). Anything submitted using CEDRI cannot later be claimed CBI. Although we do not expect persons to assert a claim of CBI, if you wish to assert a CBI claim, you must submit a complete file, including the information claimed to be CBI, on a compact disc, flash drive, or other commonly used electronic storage media to the EPA, and the electronic media must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: Group Leader, Measurement Policy Group, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same information, with the CBI omitted, must be submitted to the EPA via [email protected] or the EPA's CDX as described earlier in this paragraph. All claims of CBI must be asserted at the time of submission. Furthermore, under CAA section 114(c), emissions data is not entitled to confidential treatment, and the EPA is required to make emissions data available to the public. Thus, emissions data will not be protected as CBI and will be made publicly available.

(b)

Each owner and operator of an affected oil and natural gas source as identified in § 49.4169(b) must submit an annual report containing the information specified in paragraphs (b)(1) through (3) of this section, as applicable. The annual report must cover affected operations for the previous calendar year. The initial annual report is due April 1st of the calendar year following February 6, 2023 and must cover all affected operations for the previous calendar year on and after February 6, 2023. Subsequent annual reports are due on the same date each year as the date the initial annual report was submitted. If you own or operate more than one oil and natural gas source, you may submit one report for multiple oil and natural gas sources, provided the report contains all of the information required as specified in paragraphs (b)(1) through (3) of this section. Annual reports may coincide with title V, NSPS OOOO or OOOOa, or NESHAP HH reports as long as all the required elements of the annual report are included. An alternative schedule on which the annual report must be submitted will be allowed as long as the schedule does not extend the reporting period. The annual report must include:

(1)

The owner or operator name, and the name and location (decimal degree latitude and longitude location indicating the datum used in parentheses) of each oil and natural gas source being included in the annual report.

(2)

The beginning and ending dates of the reporting period.

(3)

For each oil and natural gas source, a summary of the required records specified in § 49.4183 that are identified in paragraphs (b)(3)(i) through (iv) of this section as they relate to the source's compliance with the requirements of §§ 49.4173 through 49.4183.

(i)

For each enclosed combustor or flare at an oil and natural gas source required under §§ 49.4173 through 49.4177:

(A)

Records of any instances in which the pilot flame is not present or the monitoring equipment is not functioning, the date and times of the occurrence, the corrective actions taken, and any preventative measures adopted to prevent recurrence of the occurrence; and

(B)

Records of any time periods in which visible smoke emissions are observed emanating from the enclosed combustor or flare.

(ii)

For each closed-vent system—

(A)

Records of any instances in which any closed-vent system or control device was bypassed or down, the reason for each incident, its duration, the corrective actions taken, and any preventative measures adopted to avoid such bypasses or downtimes; and

(B)

Records of any instances of defects identified during the monthly inspection required in § 49.4182(c), including:

(1) The date of the inspection;

(2) The findings of the inspection;

(3) Date and description of corrective adjustments or repairs made as a result of the inspection or reason for delay of repair; and

(iii)

For Fugitive Emissions Monitoring, records documenting each fugitive emissions inspection, including—

(A)

The date of the inspection;

(B)

Identification of any component that was determined to be leaking;

(C)

Identification of any component designated difficult-to-monitor or unsafe-to-monitor that was not inspected and the reason it was not inspected;

(D)

The date of repair of each leaking component;

(E)

Identification of any leaking component with a delayed repair, the reason for the delayed repair and the emission estimates associated with any shutdown and repair if the delay is longer than 6 months;

(F)

The date and description of any corrective action taken, including the date the component was verified to no longer be leaking;

(G)

The inspector's name or identification number;

(H)

For each well site complying with § 49.4178(c)(2), you must specify that the well site is exempt from the requirements of § 49.4178(d) and submit the average daily production for the well site; and

(iv)

For each pneumatic controller with a natural gas bleed rate greater than the applicable standard, records of the reason for the use of the controller.

Notes, amendments, and revision history

Source

Source: 87 FR 75376, Dec. 8, 2022, unless otherwise noted.

Authority

Authority: 42 U.S.C. 7401, et seq.

Source

Source: 63 FR 7271, Feb. 12, 1998, unless otherwise noted.