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e-CFR data is current as of October 16, 2020

Title 40Chapter ISubchapter BPart 49 → Subpart K


Title 40: Protection of Environment
PART 49—INDIAN COUNTRY: AIR QUALITY PLANNING AND MANAGEMENT


Subpart K—Implementation Plans for Tribes—Region VIII


Contents

Federal Implementation Plan for Oil and Natural Gas Well Production Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nation), North Dakota

§49.4161   Introduction.
§49.4162   Delegation of authority of administration to the tribes.
§49.4163   General provisions.
§49.4164   Construction and operational control measures.
§49.4165   Control equipment requirements.
§49.4166   Monitoring requirements.
§49.4167   Recordkeeping requirements.
§49.4168   Notification and reporting requirements.
§§49.4169-49.5510   [Reserved]

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Federal Implementation Plan for Oil and Natural Gas Well Production Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nation), North Dakota

Source: 78 FR 17858, Mar. 22, 2013, unless otherwise noted.

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§49.4161   Introduction.

(a) What is the purpose of §§49.4161 through 49.4168? Sections 49.4161 through 49.4168 establish legally and practicably enforceable requirements to control and reduce VOC emissions from well completion operations, well recompletion operations, production operations, and storage operations at existing, new and modified oil and natural gas production facilities.

(b) Am I subject to §§49.4161 through 49.4168? Sections 49.4161 through 49.4168 apply to each owner or operator constructing, modifying or operating an oil and natural gas production facility producing from the Bakken Pool with one or more oil and natural gas wells, for any one of which completion or recompletion operations are/were performed on or after August 12, 2007, that is located on the Fort Berthold Indian Reservation, which is defined by the Act of March 3, 1891 (26 Statute 1032) and which includes all lands added to the Reservation by Executive Order of June 17, 1892 (the “Fort Berthold Indian Reservation”). For the purposes of this subpart, the date that the first well completion operation at a new oil and natural gas production facility was initiated is the date that initial construction has commenced. For the purposes of this subpart, the date that a new well completion operation or the date that an existing well recompletion operation at an existing oil and natural gas production facility is initiated is the date that a modification has commenced.

(c) When must I comply with §§49.4161 through 49.4168? Compliance with §§49.4161 through 49.4168 is required no later than June 20, 2013 or upon initiation of well completion operations or well recompletion operations, whichever is later.

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§49.4162   Delegation of authority of administration to the tribes.

(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 Mandan, Hidatsa and Arikara Nation the authority to assist the EPA with administration of this Federal Implementation Plan (FIP). This section provides for administrative delegation and does not affect the eligibility criteria under 40 CFR 49.6 for treatment in the same manner as a state.

(b) How does the Tribe request delegation? In order to be delegated authority to assist us with administration of this FIP, the authorized representative of the Mandan, Hidatsa and Arikara Nation must submit a request to the Regional Administrator that:

(1) Identifies the specific provisions for which delegation is requested;

(2) Includes a statement by the Mandan, Hidatsa and Arikara Nation's legal counsel (or equivalent official) that includes the following information:

(i) A statement that the Mandan, Hidatsa and Arikara Nation are an Indian Tribe recognized by the Secretary of the Interior;

(ii) A descriptive statement demonstrating that the Mandan, Hidatsa and Arikara Nation are currently carrying out substantial governmental duties and powers over a defined area and that meets the requirements of §49.7(a)(2); and

(iii) A description of the laws of the Mandan, Hidatsa and Arikara Nation that provide adequate authority to carry out the aspects of the rule for which delegation is requested.

(3) Demonstrates that the Mandan, Hidatsa and Arikara Nation have, 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 will set forth the terms and conditions of the delegation, will specify the rule and provisions that the Mandan, Hidatsa and Arikara Nation shall be authorized to implement on behalf of the EPA, and shall be entered into by the Regional Administrator and the Mandan, Hidatsa and Arikara Nation. The Agreement will become effective upon the date that both the Regional Administrator and the authorized representative of the Mandan, Hidatsa and Arikara Nation have signed the Agreement. Once the delegation becomes effective, the Mandan, Hidatsa and Arikara Nation will be responsible, to the extent specified in the Agreement, for assisting us with administration of this FIP and shall 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 this FIP is to remain the EPA Regional Administrator and when it is intended to refer to the “Mandan, Hidatsa and Arikara Nation,” 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 Mandan, Hidatsa and Arikara Nation.

(d) How will any delegation of authority agreement be publicized? The Regional Administrator shall publish a notice in the Federal Register informing the public of any delegation of authority agreement with the Mandan, Hidatsa and Arikara Nation to assist us with administration of all or a portion of this FIP and will identify such delegation in the FIP. The Regional Administrator shall also publish an announcement of the delegation of authority agreement in local newspapers.

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§49.4163   General provisions.

(a) Definitions. As used in §§49.4161 through 49.4168, all terms not defined herein shall have the meaning given them in the Act, in subpart A and subpart OOOO of 40 CFR part 60, in the Prevention of Significant Deterioration regulations at 40 CFR 52.21, or in the Federal Minor New Source Review Program in Indian Country at 40 CFR 49.151. The following terms shall have the specific meanings given them.

(1) Bakken Pool means Oil produced from the Bakken, Three Forks, and Sanish Formations.

(2) Breathing losses means natural gas emissions from fixed roof tanks resulting from evaporative losses during storage.

(3) Casinghead natural gas means the associated natural gas that naturally dissolves out of reservoir fluids during well completion operations and recompletion operations due to the pressure relief that occurs as the reservoir fluids travel up the well casinghead.

(4) 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 natural gas from a piece or pieces of equipment to a control device or back to a process.

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

(6) Existing facility means an oil and natural gas production facility that begins actual construction prior to the effective date of the “Federal Implementation Plan for Oil and Natural Gas Well Production Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nation), North Dakota”.

(7) Flashing losses means natural gas emissions resulting from the presence of dissolved natural gas in the produced oil and the produced water, both of which are under high pressure, that occurs as the produced oil and produced water is transferred to storage tanks or other vessels that are at atmospheric pressure.

(8) Modified facility means a facility which has undergone the addition, completion, or recompletion of one or more oil and natural gas wells, and/or the addition of any associated equipment necessary for production and storage operations at an existing facility.

(9) New facility means an oil and natural gas production facility that begins actual construction after the effective date of the “Federal Implementation Plan for Oil and Natural Gas Well Production Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nation), North Dakota”.

(10) Oil means hydrocarbon liquids.

(11) Oil and natural gas production facility means all of the air pollution emitting units and activities located on or integrally connected to one or more oil and natural gas wells that are necessary for production operations and storage operations.

(12) Oil and natural gas well means a single well that extracts subsurface reservoir fluids containing a mixture of oil, natural gas, and water.

(13) Owner or operator means any person who owns, leases, operates, controls, or supervises an oil and natural gas production facility.

(14) Permit to construct or construction permit means a permit issued by the Regional Administrator pursuant to 40 CFR 49.151, 52.10 or 52.21, or a permit issued by a tribe pursuant to a program approved by the Administrator under 40 CFR part 51, subpart I, authorizing the construction or modification of a stationary source.

(15) Permit to operate or operating permit means a permit issued by the Regional Administrator pursuant to 40 CFR part 71, or by a tribe pursuant to a program approved by the Administrator under 40 CFR part 51 or 40 CFR part 70, authorizing the operation of a stationary source.

(16) Pit flare means an ignition device, installed horizontally or vertically and used in oil and natural gas production operations to combust produced natural gas and natural gas emissions.

(17) Produced natural gas means natural gas that is separated from extracted reservoir fluids during production operations.

(18) Produced oil means oil that is separated from extracted reservoir fluids during production operations.

(19) Produced oil storage tank means a unit that is constructed primarily of non-earthen materials (such as steel, fiberglass, or plastic) which provides structural support and is designed to contain an accumulation of produced oil.

(20) Produced water means water that is separated from extracted reservoir fluids during production operations.

(21) Produced water storage tank means a unit that is constructed primarily of non-earthen materials (such as steel, fiberglass, or plastic) which provides structural support and is designed to contain an accumulation of produced water.

(22) Production operations means the extraction and separation of reservoir fluids from an oil and natural gas well, using separators and heater-treater systems. A separator is a pressurized vessel designed to separate reservoir fluids into their constituent components of oil, natural gas and water. A heater-treater is a unit that heats the reservoir fluid to break oil/water emulsions and to reduce the oil viscosity. The water is then typically removed by using gravity to allow the water to separate from the oil.

(23) Regional Administrator means the Regional Administrator of EPA Region 8 or an authorized representative of the Regional Administrator.

(24) Standing losses means natural gas emissions from fixed roof tanks as a result of evaporative losses during storage.

(25) Storage operations means the transfer of produced oil and produced water to storage tanks, the filling of the storage tanks, the storage of the produced oil and produced water in the storage tanks, and the draining of the produced oil and produced water from the storage tanks.

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

(27) Utility flare means thermal oxidation system using an open (without enclosure) flame. An enclosed combustor as defined in §§49.4161 through 49.4168 is not considered a flare.

(28) Visible Smoke emissions means a pollutant generated by thermal oxidation in a flare or enclosed combustor and occurring immediately downstream of the flame. Visible smoke occurring within, but not downstream of, the flame, is not considered to constitute visible smoke emissions.

(29) Well completion means the process that allows for the flowback of oil and 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.

(30) Well completion operation means any oil and natural gas well completion using hydraulic fracturing occurring at an oil and natural gas production facility.

(31) Well recompletion operation means any oil and natural gas well completion using hydraulic refracturing occurring at an oil and natural gas production facility.

(32) Working losses means natural gas emissions from fixed roof tanks resulting from evaporative losses during filling and emptying operations.

(b) Requirement for testing. The Regional Administrator may require that an owner or operator of an oil and natural gas production facility demonstrate compliance with the requirements of the “Federal Implementation Plan for Oil and Natural Gas Well Production Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nation), North Dakota” by performing a source test and submitting the test results to the Regional Administrator. Nothing in the “Federal Implementation Plan for Oil and Natural Gas Well Production Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nation), North Dakota” limits the authority of the Regional Administrator to require, in an information request pursuant to section 114 of the Act, an owner or operator of an oil and natural gas production facility subject to the “Federal Implementation Plan for Oil and Natural Gas Production Facilities, Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nation)” to demonstrate compliance by performing testing, even where the facility does not have a permit to construct or a permit to operate.

(c) Requirement for monitoring, recordkeeping, and reporting. Nothing in “Federal Implementation Plan for Oil and Natural Gas Production Facilities, Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nation)” precludes the Regional Administrator from requiring monitoring, recordkeeping and reporting, including monitoring, recordkeeping and reporting in addition to that already required by an applicable requirement in these rules, in a permit to construct or permit to operate in order to ensure compliance.

(d) Credible evidence. For the purposes of submitting reports or establishing whether or not an owner or operator of an oil and natural gas production facility has violated or is in violation of any requirement, nothing in the “Federal Implementation Plan for Oil and Natural Gas Well Production Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nation), North Dakota” shall preclude the use, including the exclusive use, of any credible evidence or information, relevant to whether a facility would have been in compliance with applicable requirements if the appropriate performance or compliance test had been performed.

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§49.4164   Construction and operational control measures.

(a) Each owner or operator must operate and maintain all liquid and gas collection, storage, processing and handling operations, regardless of size, so as to minimize leakage of natural gas emissions to the atmosphere.

(b) During all oil and natural gas well completion operations or recompletion operations at an oil and natural gas production facility and prior to the first date of production of each oil and natural gas well, each owner or operator must, at a minimum, route all casinghead natural gas to a utility flare or a pit flare capable of reducing the mass content of VOC in the natural gas emissions vented to it by at least 90.0 percent or greater and operated as specified in §§49.4165 and 49.4166.

(c) Beginning with the first date of production from any one oil and natural gas well at an oil and natural gas production facility, each owner or operator must, at a minimum, route all natural gas emissions from production operations and storage operations to a control device capable of reducing the mass content of VOC in the natural gas emissions vented to it by at least 90.0 percent or greater and operated as specified in §§49.4165 and 49.4166.

(d) Within ninety (90) days of the first date of production from any oil and natural gas well at an oil and natural gas production facility, each owner or operator must:

(1) Route the produced natural gas from the production operations through a closed-vent system to:

(i) An operating system designed to recover and inject all the produced natural gas into a natural gas gathering pipeline system for sale or other beneficial purpose; or

(ii) A utility flare or equivalent combustion device capable of reducing the mass content of VOC in the produced natural gas vented to the device by at least 98.0 percent or greater and operated as specified in §§49.4165 and 49.4166.

(2) Route all standing, working, breathing, and flashing losses from the produced oil storage tanks and any produced water storage tank interconnected with the produced oil storage tanks through a closed-vent system to:

(i) An operating system designed to recover and inject the natural gas emissions into a natural gas gathering pipeline system for sale or other beneficial purpose; or

(ii) An enclosed combustor or utility flare capable of reducing the mass content of VOC in the natural gas emissions vented to the device by at least 98.0 percent or greater and operated as specified in §§49.4165(c) and 49.4166.

(iii) If the uncontrolled potential to emit VOCs from the aggregate of all produced oil storage tanks and produced water storage tanks interconnected with produced oil storage tanks at an oil and natural gas production facility is less than, and reasonably expected to remain below, 20 tons in any consecutive 12-month period, then, upon prior written approval by the EPA the owner or operator may use a pit flare, an enclosed combustor or a utility flare that is capable of reducing the mass content of VOC in the natural gas emissions from the storage tanks vented to the device by only 90.0 percent.

(e) In the event that pipeline injection of all or part of the natural gas collected in an operating system designed to recover and inject natural gas becomes temporarily infeasible and there is no operational enclosed combustor or utility flare at the facility, the owner or operator must route the natural gas that cannot be injected through a closed-vent system to a pit flare operated as specified in §§49.4165 and 49.4166.

(f) Produced oil storage tanks and any produced water storage tanks interconnected with produced oil storage tanks subject to the requirements specified in 40 CFR part 60, subpart OOOO are considered to meet the requirements of §49.4164(d)(2). No further requirements apply for such storage tanks under §49.4164(d)(2).

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§49.4165   Control equipment requirements.

(a) Covers. Each owner or operator must equip all openings on each produced oil storage tank and produced water storage tank interconnected with produced oil storage tanks with a cover to ensure that all natural gas emissions are efficiently being routed through a closed-vent system to a vapor recovery system, an enclosed combustor, a utility flare, or a pit flare.

(1) Each cover and all openings on the cover (e.g., access hatches, sampling ports, pressure relief valves (PRV), and gauge wells) shall form a continuous impermeable barrier over the entire surface area of the produced oil and produced water in the storage tank.

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

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

(ii) To inspect or sample the material in the unit; or

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

(3) Each thief hatch cover shall be weighted and properly seated.

(4) Each PRV shall be set to release at a pressure that will ensure that natural gas emissions are routed through the closed-vent system to the vapor recovery system, the enclosed combustor, or the utility flare under normal operating conditions.

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

(1) Each closed-vent system must route all produced natural gas and natural gas emissions from production and storage operations to the natural gas sales pipeline or the control devices required by paragraph (a) of this section.

(2) All vent lines, connections, fittings, valves, relief valves, or any other appurtenance employed to contain and collect natural gas, vapor, and fumes and transport them to a natural gas sales pipeline and any VOC control equipment must be maintained and operated properly at all times.

(3) Each closed-vent system must be designed to operate with no detectable natural gas emissions.

(4) If any closed-vent system contains one or more bypass devices, except as provided for in paragraph (b)(4)(iii) of this section, that could be used to divert all or a portion of the natural gas emissions, from entering a natural gas sales pipeline and/or any control devices, the owner or operator must meet the one of following requirements for each bypass device:

(i) At the inlet to the bypass device that could divert the natural gas emissions away from a natural gas sales pipeline or a control device and into the atmosphere, properly install, calibrate, maintain, and operate a natural gas flow indicator that is capable of taking continuous readings and sounding an alarm when the bypass device is open such that natural gas emissions are being, or could be, diverted away from a natural gas sales pipeline or a control device and into the atmosphere;

(ii) 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;

(iii) 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.

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

(1) For each enclosed combustor or utility 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) For each enclosed combustor or utility flare, 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 it by at least 98.0 percent for the minimum and maximum natural gas volumetric flow rate and BTU content routed to the device;

(3) Each enclosed combustor or utility flare must be operated to reduce the mass content of VOC in the produced natural gas and natural gas emissions routed to it by at least 98.0 percent;

(4) The owner or operator must ensure that each utility flare is designed and operated in accordance with the requirements of 40 CFR 60.18(b) for such flares, except for §60.18(c)(2) and (f)(2) for those utility flares operated with an electronically controlled automatic igniter.

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

(i) A model demonstrated by a manufacturer to the meet the VOC destruction efficiency requirements of §§49.4161 through 49.4168 using the procedure specified in 40 CFR part 60, subpart OOOO at §60.5413(d) by the due date of the first annual report as specified in §49.4168(b); or

(ii) Demonstrated to meet the VOC destruction efficiency requirements of §§49.4161 through 49.4168 using EPA approved performance test methods specified in 40 CFR part 60, subpart OOOO at §60.5413(b) by the due date of the first annual report as specified in §49.4168(b).

(6) The owner or operator must ensure that each enclosed combustor and utility flare is:

(i) Operated properly at all times that produced natural gas and/or natural gas emissions are routed to it;

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

(iii) Equipped with a flash-back flame arrestor;

(iv) Equipped with one of the following:

(A) A continuous burning pilot flame.

(B) An electronically controlled automatic igniter;

(v) Equipped with a monitoring system for continuous recording of the parameters that indicate proper operation of each enclosed combustor, utility flare, continuous burning pilot flame, and electronically controlled automatic igniter, such as a chart recorder, data logger or similar devices;

(vi) Maintained in a leak-free condition; and

(vii) Operated with no visible smoke emissions.

(d) Pit Flares. Each owner or operator must meet the following requirements for pit flares:

(1) The owner or operator must develop written operating instructions, operating procedures and maintenance schedules to ensure good air pollution control practices for minimizing emissions from the pit flare based on the site-specific design.

(2) The owner or operator must only use a pit flare for the following operations:

(i) To control produced natural gas and natural gas emissions during well completion operations or recompletion operations;

(ii) To control produced natural gas and natural gas emissions in the event that natural gas recovered for pipeline injection must be diverted to a backup control device because injection is temporarily infeasible and there is no operational enclosed combustor or utility flare at the oil and natural gas production facility. Use of the pit flare for this situation is limited to a maximum of 500 hours in any twelve (12) consecutive months; or

(iii) Control of standing, working, breathing, and flashing losses from the produced oil storage tanks and any produced water storage tank interconnected with the produced oil storage tanks if the uncontrolled potential VOC emissions from the aggregate of all produced oil storage tanks and produced water storage tanks interconnected with produced oil storage tanks is less than, and reasonably expected to remain below, 20 tons in any consecutive 12-month period.

(3) The owner or operator must only use the pit flare under the following conditions and limitations:

(i) The pit flare is operated to reduce the mass content of VOC in the produced natural gas and natural gas emissions routed to it by at least 90.0 percent;

(ii) The pit flare is operated in accordance with the site-specific written operating instructions, operating procedures, and maintenance schedules to ensure good air pollution control practices for minimizing emissions;

(iii) The pit flare is operated with no visible smoke emissions;

(iv) The pit flare is equipped with an electronically controlled automatic igniter;

(v) The pit flare is visually inspected for the presence of a flame anytime produced natural gas or natural gas emissions are being routed to it. Should the flame fail, the flame must be relit as soon as safely possible and the electronically controlled automatic igniter must be repaired or replaced before the pit flare is utilized again; and

(vi) The owner or operator does not deposit or cause to be deposited into a flare pit any oil field fluids or oil and natural gas wastes other than those designed to go to the pit flare.

(e) 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 EPA to be capable of reducing the mass content of VOC in the natural gas routed to it by at least 98.0 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 98.0 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 98.0 percent.

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§49.4166   Monitoring requirements.

(a) Each owner and operator must measure the barrels of oil produced at the oil and natural gas production facility each time the oil is unloaded from the produced oil storage tanks using the methodologies of tank gauging or positive displacement metering system, as appropriate, as established by the U.S. Department of the Interior's Bureau of Land Management at 43 CFR part 3160, in the “Onshore Oil and Gas Operations; Federal and Indian Oil & Gas Leases; Onshore Oil and Gas Order No. 4; Measurement of Oil”.

(b) Each owner or operator must monitor the hours that each pit flare is operated to control produced natural gas and natural gas emissions in the event that natural gas recovered for pipeline injection must be diverted to a backup control device because injection is temporarily infeasible and there is no enclosed combustor or utility flare at the oil and natural gas production facility.

(c) Each owner or operator must monitor the volume of produced natural gas sent to each enclosed combustor, utility flare, and pit flare at all times. Methods to measure the volume include, but are not limited to, direct measurement and gas-to-oil ratio (GOR) laboratory analyses.

(d) Each owner or operator must monitor the volume of standing, working, breathing, and flashing losses from the produced oil and produced water storage tanks sent to each vapor recovery system, enclosed combustor, utility flare, and pit flare at all times. Methods to measure the volume include, but are not limited to, direct measurement or GOR laboratory analyses.

(e) Each owner or operator must perform quarterly visual inspections of tank thief hatches, covers, seals, PRVs, and closed vent systems to ensure proper condition and functioning and repair any damaged equipment. The quarterly inspections must be performed while the produced oil and produced water storage tanks are being filled.

(f) Each owner or operator must perform quarterly visual inspections of the peak pressure and vacuum values in each closed vent system and control system for the produced oil and produced water storage tanks to ensure that the pressure and vacuum relief set-points are not being exceeded in a way that has resulted, or may result, in venting and possible damage to equipment. The quarterly inspections must be performed while the produced oil and produced water storage tanks are being filled.

(g) Each owner or operator must monitor the operation of each enclosed combustor, utility flare, and pit flare to confirm proper operation as follows:

(1) Continuously monitor all variable operational parameters specified in the written operating instructions and procedures, including continuous burning pilot flame, electronically controlled automatic igniters, and monitoring system failures, using a malfunction alarm and remote notification system, where such systems are available, or continuously monitor under an equivalent alternative protocol upon prior written approval by the EPA;

(2) Perform a physical inspection of all equipment associated with each enclosed combustor, utility flare, and pit flare each time an operator is on site, at a minimum quarterly, to ensure system integrity;

(3) Monitor for visible smoke during operation of any enclosed combustor, utility flare or pit flare each time an operator is on site, at a minimum quarterly. Upon observation of visible smoke, use EPA Reference Method 22 of 40 CFR part 60, Appendix A, to determine whether visible smoke emissions are present. The observation period shall be 2 hours. Visible smoke emissions are present if smoke is observed for more than 5 minutes in any 2 consecutive hours; and

(4) Respond to any observation of any continuous burning pilot flame failure, electronically controlled automatic igniter failure, or improper monitoring equipment operation and ensure the equipment is returned to proper operation as soon as practicable and safely possible after an observation or an alarm sounds.

(h) Where sufficient to meet the monitoring and recordkeeping requirements in §§49.4166 and 49.4167, the owner or operator may use a Supervisory Control and Data Acquisition (SCADA) system to monitor and record the required data in §§49.4161 through 49.4168.

(i) Other Monitoring Options. The owner or operator may use equivalent methods of monitoring other than those listed above upon prior written approval by the EPA.

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§49.4167   Recordkeeping requirements.

(a) Each owner or operator must maintain the following records:

(1) The measured barrels of oil produced at the oil and natural gas production facility each time the oil is unloaded from the produced oil storage tanks;

(2) The volume of produced natural gas sent to each enclosed combustor, utility flare, and pit flare at all times;

(3) The volume of natural gas emissions from the produced oil storage tanks and produced water storage tanks sent to each enclosed combustor, utility flare, and pit flare at all times;

(4) A summary of each oil and natural gas well completion operation and recompletion operation at an oil and natural gas production facility. Each summary shall include:

(i) The latitude and longitude location of the oil and natural gas well in decimal format;

(ii) The date, time, and duration in hours of flowback from the oil and natural gas well;

(iii) The date, time, and duration in hours of any venting of casinghead natural gas from the oil and natural gas well; and

(iv) Specific reasons for each instance of venting in lieu of capture or combustion.

(5) For each enclosed combustor, utility flare, and pit flare at an oil and natural gas production facility:

(i) Written, site-specific designs, operating instructions, operating procedures and maintenance schedules;

(ii) Records of all required monitoring of operations;

(iii) Records of any deviations from the operating parameters specified by the written site-specific designs, operating instructions, and operating procedures. The records must include the enclosed combustor, utility flare, or pit flare's total operating time during which a deviation occurred, the date, time and length of time that deviations occurred, and the corrective actions taken and any preventative measures adopted to operate the device within that operating parameter;

(iv) Records of any instances in which the pilot flame is not present, electronically controlled automatic igniter is not functioning, or the monitoring equipment is not functioning in the enclosed combustor, the utility flare, or the pit flare, the date and times of the occurrence, the corrective actions taken, and any preventative measures adopted to prevent recurrence of the occurrence;

(v) Records of any instances in which a recording device installed to record data from the enclosed combustor, utility flare, or pit flare is not operational; and

(vi) Records of any time periods in which visible smoke emissions are observed emanating from the enclosed combustor, utility flare, or pit flare.

(6) For each pit flare at an oil and natural gas production facility, a demonstration of compliance with the use restrictions set forth in §49.4165(d)(2)(ii) is made by keeping records in a log book, or similar recording system, during each period of time that the pit flare is operating. The records must contain the following information:

(i) Date and time the pit flare was started up and subsequently shut down;

(ii) Total hours operated when pipeline injection was temporarily infeasible for the current calendar month plus the previous consecutive eleven (11) calendar months; and

(iii) Brief descriptions of the justification for each period of operation.

(7) 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 volume of natural gas emissions released, and the corrective actions taken and any preventative measures adopted to avoid such bypasses or downtimes; and

(8) Documentation of all produced oil storage tank and produced water storage tank inspections required in §49.4166(e) and (f). All inspection records must include, at a minimum, 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 inspections, and the date of the adjustment or repair; and

(iv) The inspector's name and signature.

(b) Each owner or operator must keep all records required by this section onsite at the facility or at the location that has day-to-day operational control over the facility 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 five (5) years from the date the record was created.

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§49.4168   Notification and reporting requirements.

(a) Each owner or operator must submit any documents required under this section to: U.S. Environmental Protection Agency, Region 8 Office of Enforcement, Compliance & Environmental Justice, Air Toxics and Technical Enforcement Program, 8ENF-AT, 1595 Wynkoop Street, Denver, Colorado 80202. Documents may be submitted electronically to r8airreportenforcement@epa.gov.

(b) Each owner and operator must submit an annual report containing the information specified in paragraphs (b)(1) through (4) of this section. Each annual report is due August 15th every year and must cover all information for the previous calendar year. The initial report must cover the cumulative information for that year. If you own or operate more than one oil and natural gas production facility, you may submit one report for multiple oil and natural gas production facilities provided the report contains all of the information required as specified in paragraphs (b)(1) through (4) of this section. Annual reports may coincide with title V reports as long as all the required elements of the annual report are included. The EPA may approve a common schedule on which reports required by §§49.4161 through 49.4168 may be submitted as long as the schedule does not extend the reporting period.

(1) The company name and the address of the oil and natural gas production facility or facilities.

(2) An identification of each oil and natural gas production facility being included in the annual report.

(3) The beginning and ending dates of the reporting period.

(4) For each oil and natural gas production facility, the information in paragraphs (b)(4)(i) through (iv) of this section.

(i) A summary of all required records identifying each oil and natural gas well completion or recompletion operation for each oil and natural gas production facility conducted during the reporting period;

(ii) An identification of the first date of production for each oil and natural gas well at each oil and natural gas production facility that commenced production during the reporting period; and

(iii) A summary of cases where construction or operation was not performed in compliance with the requirements specified in §49.4164, §49.4165, or §49.4166 for each oil and natural gas well at each oil and natural gas production facility, and the corrective measures taken.

(iv) A certification by a responsible official of truth, accuracy and completeness. This certification shall state that, based on information and belief formed after reasonable inquiry, the statements and information in the document are true, accurate and complete.

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§§49.4169-49.5510   [Reserved]

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