5B7 DIVISION 7: OIL AND NATURAL GAS IN OZONE NONATTAINMENT AREAS, SIP effective September 14, 2023 (TXd239)

Regulatory Text:
Texas Commission on Environmental Quality

5 Texas Chapter 115 : Control of Air Pollution from Volatile Organic Compounds

5B SUBCHAPTER B: GENERAL VOLATILE ORGANIC COMPOUND SOURCES

5B7 DIVISION 7: OIL AND NATURAL GAS IN OZONE NONATTAINMENT AREAS
New Division SIP effective September 14, 2023 (TXd239).
As adopted by TCEQ June 30, 2021 effective July 21, 2023 ,
Submitted to EPA July 20, 2021 (TX-438),
Regulations.gov document EPA-R06-OAR-2021-0525-0003, Adobe file pages 306 to 381.
Approved by EPA August 15, 2023 (88 FR 55379) SIP effective September 14, 2023 (TXd239).
Explanations: no explanations for approved Sections 115.170 to 183.
Regulations.gov docket EPA-R06-OAR-2021-0525.

List of Sections:
Section 115.170 Applicability. TXd239
Section 115.171 Definitions. TXd239
Section 115.172 Exemptions. TXd239
Section 115.173 Compressor Control Requirements. TXd239
Section 115.174 Pneumatic Controller and Pump Control Requirements. TXd239
Section 115.175 Storage Tank Control Requirements. TXd239
Section 115.176 Alternative Control Requirements. TXd239
Section 115.177 Fugitive Emission Component Monitoring Requirements. TXd239
Section 115.178 Monitoring and Inspection Requirements. TXd239
Section 115.179 Approved Test Methods and Testing Requirements. TXd239
Section 115.180 Recordkeeping Requirements. TXd239
Section 115.181 Reporting Requirements. TXd239
Section 115.183 Compliance Schedules. TXd239
**********end 5B7 List of Sections****************

§115.170. Applicability.
SIP effective September 14, 2023 (TXd239),
Regulations.gov document EPA-R06-OAR-2021-0525-0003, Adobe file pages 306 to 307.
The requirements in this division apply to the following equipment in the Dallas-Fort Worth and Houston-Galveston-Brazoria areas as defined in §115.10 of this title (relating to Definitions):
(1) any centrifugal compressor with wet seals and any reciprocating compressor located between the wellhead, but not including the well site, and point of custody transfer to a natural gas transmission or storage operation;
(2) any pneumatic controller located from the wellhead to a natural gas processing plant, including the natural gas processing plant, or point of custody transfer to a crude oil pipeline;
(3) any pneumatic pump located at a well site or a natural gas processing plant;
(4) any storage tank located from the well site to the point of custody transfer to an oil pipeline or to the point of natural gas distribution; and
(5) any fugitive emission component in volatile organic compounds service located at a crude oil or natural gas production well site, natural gas processing plant, or gathering and boosting station.
Adopted by TCEQ June 30, 2021, Effective July 21, 2023
***end Texas Section 115.170 SIP Effective September 14, 2023 (TXd239)***dzs***

§115.171. Definitions.
SIP effective September 14, 2023 (TXd239),
Regulations.gov document EPA-R06-OAR-2021-0525-0003, Adobe file pages 307 to 313.
Unless specifically defined in the Texas Clean Air Act (Texas Health and Safety Code, Chapter 382) or in §§3.2, 101.1, or 115.10 of this title (relating to Definitions, respectively), the terms in this division have the meanings commonly used in the field of air pollution control. The following meanings apply in this division unless the context clearly indicates otherwise.
(1) Centrifugal compressor--A piece of equipment for raising the pressure of natural gas by drawing in low-pressure natural gas and discharging significantly higher-pressure natural gas by means of mechanical rotating vanes or impellers. Screw, sliding vane, and liquid ring compressors are not centrifugal compressors.
(2) Closure device--A piece of equipment that covers an opening in the roof of a fixed roof storage tank and either can be temporarily opened or has a component that provides a temporary opening. Examples of closure devices include, but are not limited to, thief hatches, pressure relief valves, pressure-vacuum relief valves, and access hatches.
(3) Difficult-to-monitor--Equipment that cannot be inspected without elevating the inspecting personnel more than two meters above a support surface.
(4) Fugitive emission components--Except for vents as defined in §101.1 of this title (relating to Definitions) and sampling systems, equipment as defined in subparagraphs (A) and (B) of this paragraph that has the potential to leak volatile organic compounds (VOC) emissions.
(A) At a natural gas processing plant, equipment considered fugitive components include, but are not limited to, any pump, pressure relief device, open-ended valve or line, valve, flange, or other connector that is in VOC service or wet gas service, and any closed vent system or control device not subject to another section in this division that specifies one or more instrument monitoring requirements for the system or
device. A compressor or sampling connection system that is exempt from the fugitive monitoring requirements in §115.352 and §115.354 of this title (relating to Fugitive
Emission Control in Petroleum Refining, Natural Gas/Gasoline Processing, and
Petrochemical Processes in Ozone Nonattainment Areas) on or before December 31, 2022
is excluded as a fugitive monitoring component under this subparagraph.
(B) At a well site or gathering and boosting station from equipment considered fugitive emissions components include, but are not limited to, valves, compressors, connectors, pressure relief devices, open-ended lines, flanges, instruments, meters, or other openings that are not on a storage tank subject to §115.175 of this title (relating to Storage Tank Control Requirements), and any closed vent system or control device not subject to another section in this division that specifies one or more instrument monitoring requirements for the system or device. A compressor seal at a
gathering and boosting station that is addressed in §115.173 of this title (relating to
Compressor Control Requirements) is not included as a fugitive emission component.
(5) Gathering and boosting station--Any permanent combination of one or more compressors that collects natural gas from well sites and moves the natural gas at increased pressure into gathering pipelines to a natural gas processing plant or into the pipeline. The combination of one or more compressors located at a well site, or located at an onshore natural gas processing plant, is not a gathering and boosting station.
(6) Heavy liquid service--An equipment is in heavy liquid service if the weight percent evaporated is 10.0% or less at 302 degrees Fahrenheit (150 degrees Celsius) as determined by ASTM Method D86-96.
(7) Light liquid service--A piece of equipment contains a liquid that meets
the following conditions.
(A) The vapor pressure of one or more of the organic components is greater than 1.2 inches water at 68 degrees Fahrenheit (0.3 kilopascals at 20 degrees Celsius).
(B) The total concentration of the pure organic components having a vapor pressure greater than 1.2 inches water at 68 degrees Fahrenheit (0.3 kilopascals at 20 degrees Celsius) is equal to or greater than 20.0% by weight.
(C) The fluid is a liquid at operating conditions.
(D) An equipment is in light liquid service if the weight percent
evaporated is greater than 10.0% at 302 degrees Fahrenheit (150 degrees Celsius) as
determined by ASTM Method D86-96.
(8) Natural gas processing plant--any processing site engaged in the extraction of natural gas liquids from field gas, fractionation of mixed natural gas liquids to natural gas products, or both. A Joule-Thompson valve, a dew point depression valve, or an isolated or standalone Joule-Thompson skid is not a natural gas processing plant.
(9) Pneumatic controller--An automated instrument that is actuated by a compressed gas and is used to maintain a process condition such as liquid level, pressure, pressure differential and temperature. When actuated by natural gas, pneumatic controllers are characterized primarily by their emission characteristics.
(A) Continuous bleed pneumatic controllers receive a continuous flow of pneumatic natural gas supply and are used to modulate flow, liquid level, or pressure. Gas is vented continuously at a rate that may vary over time. Continuous bleed controllers are further subdivided into two types based on their bleed rate, which for the purposes of this section means the rate at which natural gas is continuously vented from a pneumatic controller and measured in standard cubic feet per hour (scfh):
(i) low bleed controllers have a bleed rate of less than or equal to 6.0 scfh; and
(ii) high bleed controllers have a bleed rate of greater than 6.0 scfh.
(B) Intermittent bleed or snap-acting pneumatic controllers release natural gas only when they open or close a valve or as they throttle the gas flow.
(C) Zero-bleed pneumatic controllers do not bleed natural gas to the atmosphere. These pneumatic controllers are self-contained devices that release gas to a downstream pipeline instead of to the atmosphere.
(10) Pneumatic pump--A positive displacement pump powered by pressurized natural gas that uses the reciprocating action of flexible diaphragms in conjunction with check valves to pump a fluid.
(11) Reciprocating compressor--A piece of equipment that increases the pressure of a natural gas by positive displacement, employing linear movement of the driveshaft.
(12) Rod packing--A series of flexible rings in machined metal cups that fit around the reciprocating compressor piston rod to create a seal limiting the amount of compressed natural gas that escapes to the atmosphere, or other mechanism that provides the same function.
(13) Route to a process--The emissions are:
(A) conveyed via a closed vent system to any enclosed portion of a process where it is predominantly recycled or consumed in the same manner as a material that fulfills the same function in the process or is transformed by chemical reaction into materials that are not regulated materials or incorporated into a product; or
(B) recovered.
(14) Storage tank--A tank, stationary vessel, or a container that contains an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water, and that is constructed primarily of non-earthen materials.
(15) Unsafe-to-monitor--Equipment that exposes monitoring personnel to an imminent or potential danger as a consequence of conducting an inspection.
(16) Vapor recovery unit--A device that transfers hydrocarbon vapors to a fuel liquid or gas system, a sales liquid or gas system, or a liquid storage tank.
(17) Well site--A parcel of land with one or more surface sites, which means sites with any combination of one or more graded pad sites, gravel pad sites, foundations, platforms, or the immediate physical location upon which equipment is physically affixed, that are constructed for the drilling and subsequent operation of one or more oil, natural gas, or injection wells. The meaning of "site" and "sites" in this definition is limited to this division.
(18) Wet gas service--A piece of equipment which contains or contacts the field gas before the extraction step at a gas processing plant process unit.
Adopted by TCEQ June 30, 2021, Effective July 21, 2023
***end Texas Section 115.171 SIP Effective September 14, 2023 (TXd239)***dzs***

§115.172. Exemptions.
SIP effective September 14, 2023 (TXd239),
Regulations.gov document EPA-R06-OAR-2021-0525-0003, Adobe file pages 314 to 318.
(a) The following exemptions apply to the equipment specified in §115.170 of this title (relating to Applicability) that is subject to this division. Records to support exemption qualification must be kept in accordance with the requirements in §115.180 of this title (relating to Recordkeeping Requirements). Additional requirements apply where specified.
(1) Boilers and process heaters are exempt from the testing requirements of §115.179 of this title (relating to Approved Test Methods and Testing Requirements) and the monitoring requirements of §115.178 of this title (relating to Monitoring and Inspection Requirements) if:
(A) a vent gas stream from equipment subject to this division is introduced with the primary fuel or is used as the primary fuel; or
(B) the boiler or process heater has a design heat input capacity equal to or greater than 44 megawatts or 149.6 million British thermal units per hour.
(2) Any pneumatic pump at a well site that operates fewer than 90 days per calendar year at a well site is exempt from the requirements of this division.
(3) Except for the control requirements in §115.175(b) or (c) of this title (relating to Storage Tank Control Requirements), any storage tank that meets one of the following conditions is exempt from the requirements in this division:
(A) a storage tank with the potential to emit of less than 6.0 tons per year of volatile organic compounds (VOC) emissions, which must be calculated in accordance with §115.175(c)(2) of this title;
(B) a storage tank with uncontrolled actual VOC emissions of less than 4.0 tons per year, which must be calculated in accordance with §115.175(c)(1) of this title;
(C) a process vessel such as a surge control vessel, bottom receiver, or knockout vessel;
(D) a pressure vessel designed to operate in excess of 29.7 pounds per square inch absolute and designed to operate without emissions to the atmosphere; and
(E) a vessel that is skid-mounted or permanently attached to something that is mobile (such as trucks, railcars, barges, or ships) and is intended to be located at a site for less than 180 consecutive days.
(4) Fugitive emission components at a natural gas processing plant that contact a process fluid that contains less than 1.0% VOC by weight are exempt from the requirements of this division.
(5) All pumps and compressors, other than those specified in §115.173 and §115.174 of this title (relating to Compressor Control Requirements and Pneumatic Controller and Pump Controller Requirements, respectively), that are equipped with a shaft sealing system that prevents or detects emissions of VOC from the seal are exempt from the fugitive monitoring requirements of §115.177 of this title (relating to Fugitive Emission Component Requirements). These seal systems may include, but are not limited to, dual pump seals with barrier fluid at higher pressure than process pressure, seals degassing to vent control systems kept in good working order, or seals equipped with an automatic seal failure detection and alarm system.
(6) At a natural gas processing plant, components that are insulated, making them inaccessible to monitoring with a hydrocarbon gas analyzer, are exempt from the hydrocarbon gas analyzer monitoring requirements of §115.177 and §115.178 of this title. Inspections using audio, visual, and olfactory means must still be conducted in accordance with the appropriate requirements of §115.177 and §115.178 of this title.
(7) At a natural gas processing plant, sampling connection systems, as defined in 40 Code of Federal Regulations (CFR) §63.161 (as amended January 17, 1997 (62 FR 2788)), that meet the requirements of 40 CFR §63.166(a) and (b) (as amended June 20, 1996 (61 FR 31439)) are exempt from the requirements of this division, except from the recordkeeping requirement in §115.180(2) of this title.
(8) Fugitive emission components located at a well site with one or more wells that produce on average 15-barrel equivalents or less per day are exempt from the requirements of this division, except from the recordkeeping requirement in §115.180(2) of this title.
(b) Equipment used only for materials outside the product stream from a crude oil or natural gas production well or after the point of custody transfer to a crude oil or natural gas distribution or storage segment is exempt from the requirements of this division.
(c) After the appropriate compliance date in §115.183 of this title (relating to Compliance Schedules) and upon the date that the wet seals on a centrifugal compressor subject to subsection (a) of this section are retrofitted with a dual mechanical or other equivalent dry seal control system, the compressor no longer meets the applicability of this division.
(d) After the appropriate compliance date in §115.183 of this title, if changes are made to a pneumatic pump or controller are such that the pump or controller does not meet the appropriate definitions in this division, the requirements of§115.174(a) or (b) of this title no longer apply. The change in applicability status must be documented in accordance with the recordkeeping requirements in §115.180 of this title. For example, a pneumatic controller converted to a solar-powered controller no longer meets the applicability of a pneumatic controller regulated by this division.
Adopted by TCEQ June 30, 2021, Effective July 21, 2023
***end Texas Section 115.172 SIP Effective September 14, 2023 (TXd239)***dzs***

§115.173. Compressor Control Requirements.
SIP effective September 14, 2023 (TXd239),
Regulations.gov document EPA-R06-OAR-2021-0525-0003, Adobe file pages 318 to 321.
The control requirements in this section apply to any centrifugal compressor and reciprocating compressor subject to this division.
(1) If routing to a control device or routing to a process, the volatile organic compounds (VOC) vapors must be routed from the wet seal fluid degassing system or rod packing through a closed vent system. The closed vent system must be designed and operated to route all gases, vapors, or fumes from the wet seal fluid degassing system or rod packing to the control device under normal operation. The closed vent system must operate under negative pressure at the inlet for vapors.
(2) A compressor must be equipped with a seal cover that forms a continuous impermeable barrier over the entire liquid surface area, and the cover must remain in a sealed position (e.g., covered by a gasketed lid or cap) except during periods necessary to inspect, maintain, repair, or replace equipment.
(3) The owner or operator shall control VOC emissions from a centrifugal compressor wet seal fluid degassing system or reciprocating compressor rod packing properly using one of the following controls.
(A) A control device, other than a device specified in subparagraphs (B) and (C) of this paragraph, may be used and must maintain a VOC control efficiency of at least 95% or a VOC concentration of equal to or less than 275 parts per million by volume (ppmv), as propane, on a wet basis corrected to 3% oxygen. The 95% VOC control efficiency and 275 ppmv VOC concentration are calculated from the gas stream at the control device outlet.
(i) The control device must be operated at all times when gases, vapors, or fumes are vented from the closed vent system to the control device. For a boiler or process heater used as the control device, the vent gas stream must be introduced into the flame zone of the boiler or process heater. Multiple vents may be routed to the same control device. Control devices and closed vent systems must be in compliance with §115.178 of this title (relating to Monitoring and Inspection Requirements) and §115.179 of this title (relating to Approved Test Methods and Testing Requirements).
(ii) Control devices must operate with no visible emissions, as determined through a visible emissions test conducted according to United States Environmental Protection Agency (EPA) Method 22, 40 Code of Federal Regulations (CFR) Part 60, Appendix A-7, Section 11, except for periods not to exceed a total of one minute during any 15-minute observation period.
(B) A flare may be used and must be designed and operated in accordance with 40 CFR §60.18(b) -(f) (as amended through December 22, 2008 (73 FR 78209)). The flare must be lit at all times when VOC vapors are routed to the flare. Multiple vents may be routed to the same control device.
(C) VOC emissions may be routed to a process if the emissions are compatible with the process and would be retained within the process. Routing to a process is considered equivalent to a 95% control efficiency.
(D) The reciprocating compressor rod packing may be replaced on or before the compressor has operated for 26,000 hours from the most recent rod packing replacement. The number of hours the compressor operates must be continuously recorded beginning on the appropriate compliance date in §115.183 of this title (relating to Compliance Schedule).
(E) The reciprocating compressor rod packing may be replaced within 36 months from the most recent rod packing replacement beginning from the appropriate compliance date in §115.183 of this title.
(4) The following requirements apply to a bypass installed on a closed vent system able to divert any portion of the flow from entering a control device or routing to a process.
(A) A flow indicator must be installed, calibrated, and maintained at the inlet of each bypass. The flow indicator must take a reading at least once every 15 minutes and initiate an alarm notifying operators to take prompt remedial action when bypass flows are present.
(B) Each bypass valve must be secured in the non-diverting position using a car-seal or a lock-and-key type configuration.
Adopted by TCEQ June 30, 2021, Effective July 21, 2023
***end Texas Section 115.173 SIP Effective September 14, 2023 (TXd239)***dzs***

§115.174. Pneumatic Controller and Pump Control Requirements.
SIP effective September 14, 2023 (TXd239),
Regulations.gov document EPA-R06-OAR-2021-0525-0003, Adobe file pages 321 to 313 to 326.
(a) The following control requirements apply to any pneumatic pump or pneumatic controller at a natural gas processing plant.
(1) The pneumatic pump drive must not emit volatile organic compounds (VOC) emissions to the atmosphere.
(2) Each single continuous-bleed pneumatic controller must have a natural gas bleed rate equal to 0.0 standard cubic feet per hour (scfh).
(b) The following control requirements apply to any pneumatic pump or pneumatic controller subject to this division at a location other than at a natural gas processing plant.
(1) VOC emissions from each pneumatic pump must be reduced by 95%.
(2) Each pneumatic controller must have a natural gas bleed rate of less than or equal to 6.0 scfh.
(c) A control device used to comply with this section must meet one of the following conditions at all times when VOC vapors are routed to the control device or to a process. Multiple vents may be routed to the same control device or process. The VOC vapors must be routed through a closed vent system, which must be designed and operated to route all captured VOC vapors to a process or a control device under normal operations. Control devices and closed vent systems must be in compliance with §115.178 of this title (relating to Monitoring and Inspection Requirements) and §115.179 of this title (relating to Approved Test Methods and Testing Requirements).
(1) A control device, other than a device specified in paragraphs (2) and (3) of this subsection, may be used and must maintain a minimum control efficiency of at least 95% or a VOC concentration of equal to or less than 275 parts per million by volume (ppmv), as propane, on a wet basis corrected to 3% oxygen. The 95% VOC control efficiency and 275 ppmv VOC concentration are calculated from the gas stream at the control device outlet. For a boiler or process heater used as the control device, the vent gas stream must be introduced into the flame zone of the boiler or process heater.
(2) A flare may be used and must be designed and operated in accordance with 40 Code of Federal Regulations (CFR) §60.18(b) - (f) (as amended through December 22, 2008 (73 FR 78209)). The flare must be lit at all times when VOC vapors are routed to the flare.
(3) VOC emissions may be routed to a process if the emissions are compatible with the process and would be retained within the process. Routing to a process is considered equivalent to a 95% control efficiency.
(4) A control device used to comply with paragraph (1) of this subsection must operate with no visible emissions, as determined through a visible emissions test conducted according to United States Environmental Protection Agency (EPA) Method 22, 40 CFR Part 60, Appendix A-7, Section 11 (as amended March 16, 2015 (83 FR 13751)), except for periods not to exceed a total of one minute during any 15-minute observation period.
(d)The following requirements apply to a bypass installed on a closed vent system able to divert any portion of the flow from entering a control device or routing to a process.
(1) A flow indicator must be installed, calibrated, and maintained at the inlet of each bypass. The flow indicator must take a reading at least once every 15 minutes and initiate an alarm notifying operators to take prompt remedial action when bypass flows are present.
(2) Each bypass valve must be secured in the non-diverting position using a car-seal or a lock-and-key type configuration.
(e) The following exceptions apply, as specified, to the pneumatic controller or pneumatic pump control requirements in subsections (a) or (b) of this section.
(1) By the appropriate compliance date in §115.183 of this title (relating to Compliance Schedules), the VOC emissions from a pneumatic pump at a well site for which a control device does not exist and for which routing to a process is technically infeasible, as demonstrated in paragraph (3) of this subsection, are not required to be controlled in accordance with subsection (b) of this section. The owner or operator shall maintain records documenting that there is no control device available and whereupon this exclusion no longer applies, the owner or operator shall be in compliance with the control requirements of subsection (b) of this section and shall keep records documenting the change in compliance with the initial report as required in §115.180 of this title (relating to Recordkeeping Requirements).
(2) By the appropriate compliance date in §115.183 of this title, a control device located at the same site as a pneumatic pump, and with which controlling the VOC emissions from the pneumatic pump is technically feasible, that achieves a control efficiency less than 95% must be used if a control device achieving a 95% control efficiency is not available. If more than one control device with less than 95% control efficiency is available, the control device with the highest control efficiency must be used. The same monitoring, testing, and recordkeeping requirements apply to such a control device that apply to control devices in subsection (c) of this section.
(3) For a pneumatic pump located at a well site for which the control requirements in this section are technically infeasible, the owner or operator shall make a demonstration of technical infeasibility in accordance with §115.176(b) of this title (relating to Alternative Control Requirements). Upon the date the demonstration of technical infeasibility is no longer true, whereupon this exclusion no longer applies, the owner or operator shall comply with the control requirements of this section and shall keep records documenting the change in compliance with the initial report as required in §115.180 of this title.
(4) For a pneumatic controller for which there is a functional need for a bleed rate greater than the limits in subsection (a) of this section, the owner or operator shall make and maintain record of a determination of functional need in accordance with §115.176(c) of this title. Upon the date the determination of functional need is no longer true, the owner or operator shall comply with the control requirements of this section and shall keep records documenting the change in compliance with the initial report as required in §115.180 of this title.
(f) Pneumatic pumps and controllers subject to this division must be operated and maintained in accordance with manufacturer’s recommendations.
Adopted by TCEQ June 30, 2021, Effective July 21, 2023
***end Texas Section 115.174 SIP Effective September 14, 2023 (TXd239)***dzs***

§115.175. Storage Tank Control Requirements.
SIP effective September 14, 2023 (TXd239),
Regulations.gov document EPA-R06-OAR-2021-0525-0003, Adobe file pages 326 to 336.
(a) No person shall place, store, or hold crude oil or condensate in any storage tank unless the tank is capable of maintaining working pressure sufficient at all times to prevent any vapor or gas loss to the atmosphere or is in compliance with the following controls.
(1) All openings in a fixed roof storage tank through which vapors are not routed to a vapor recovery unit or other control device specified in paragraph (2) of this subsection, must be equipped with a closure device maintained according to the manufacturer's instructions and operated according to this paragraph. If manufacturer instructions are unavailable, industry standards consistent with good engineering practice can be substituted.
(A) Each closure device must be closed at all times except when normally actuated or required to be open for temporary access or to relieve excess pressure or vacuum in accordance with the manufacturer's design and consistent with good air pollution control practices. Such opening, actuation, or use must be limited to minimize vapor loss.
(B) Each closure device must be properly sealed to minimize vapor loss and must form a continuous impermeable barrier over the entire surface area of the liquid in the storage tank when closed.
(C) Each closure device must either be latched closed or, if designed to relieve pressure, set to automatically open at a pressure that will ensure all vapors are routed to the vapor recovery unit or other control device under normal operating conditions other than gauging the tank or taking a sample through an open thief hatch.
(D) No closure device may be allowed to have a volatile organic compound (VOC) leak for more than 15 calendar days after the leak is found unless delay of repair is allowed. For the purposes of this subparagraph, a leak is the exuding of process gasses from a closed device detected by audio, visual, and olfactory means. If parts are unavailable, repair may be delayed. Parts must be ordered promptly, and the repair must be completed within five days of receipt of required parts. Repair may be delayed until the next shutdown if the repair of the component would require a shutdown that would create more emissions than the repair would eliminate. Repair must be completed by the end of the next shutdown.
(2) A control device used to comply with this subsection must meet one of the following conditions at all times when VOC vapors are routed to the device. The VOC vapors must be routed through a closed vent system that must be designed and operated to route to a control device, including to route to a process, all captured VOC vapor under normal operations. Multiple vents may be routed to the same control device. Control devices and closed vent systems must comply with the requirements of §115.178 of this title (relating to Monitoring and Inspection Requirements) and §115.179 of this title (relating to Approved Test Methods and Testing Requirements).
(A) A control device, other than a device specified in subparagraphs (B) and (C) of this paragraph, to which VOC vapors are routed, must maintain a control efficiency of at least 95% or a VOC concentration of equal to or less than 275 parts per million by volume (ppmv), as propane, on a wet basis corrected to 3% oxygen. The 95% VOC control efficiency and 275 ppmv VOC concentration are calculated from the gas stream at the control device outlet. For a boiler or process heater used as the control device, the vent gas stream must be introduced into the flame zone of the boiler or process heater.
(B) A flare must be designed and operated in accordance with 40 Code of Federal Regulations (CFR) §60.18(b) - (f) (as amended through December 22, 2008 (73 FR 78209)). The flare must be lit at all times when VOC vapors are routed to the flare.
(C) A vapor recovery unit must be designed to process all vapor generated by the maximum liquid throughput of the storage tank or the aggregate of storage tanks in a tank battery and must transfer recovered vapors to a pipe or container that is vapor-tight, as defined in §115.10 of this title (relating to Definitions).
(D) A control device, used to comply with subparagraph (A) of this paragraph, must operate with no visible emissions, as determined through a visible emissions test conducted according to United States Environmental Protection Agency (EPA) Method 22, 40 CFR Part 60, Appendix A-7, Section 11 (as amended March 16, 2015 (83 FR 13751)), except for periods not to exceed a total of one minute during any 15minute observation period.
(3) Beginning on the appropriate compliance date in §115.183 of this title (relating to Compliance Schedules), any storage tank that stores crude oil or condensate with a true vapor pressure of greater than or equal to 11 pounds per square inch absolute (psia) and a storage capacity of at least 40,000 gallons, and was required to use a submerged fill pipe under Table 2 in §115.112(e)(1) of this title (relating to Control Requirements), must continue to use a submerged fill pipe.
(4) The following requirements apply to a bypass installed on a closed vent system able to divert any portion of the flow from entering a control device or routing to a process.
(A) A flow indicator must be installed, calibrated, and maintained at the inlet of each bypass. The flow indicator must take a reading at least once every 15 minutes and initiate an alarm notifying operators to take prompt remedial action when bypass flows are present.
(B) Each bypass valve must be secured in the non-diverting position using a car-seal or a lock-and-key type configuration.
(b) Any storage tank with the potential to emit less than 6.0 tons per year of VOC, and any storage tank with the potential to emit at least 6.0 tons per year of VOC emissions but that demonstrates uncontrolled actual VOC emissions are less than 4.0 tons per year, is not required to be in compliance with the control requirements in subsection (a) of this section unless the tank was required to comply with a control requirement in §115.112(e) of this title on or before December 31, 2022. The owner or operator shall continue to comply with the control requirement that applied as of December 31, 2022 in the Table in §115.112(e) of this title. The calculation of emissions
demonstrating that actual VOC emissions are less than 4.0 tons per year for 12
consecutive months based on average monthly throughput must be performed on a
monthly basis.

Figure: 30 TAC §115.175(b)

True Vapor Pressure	Storage Capacity in gallons (gal)	Control Requirements
=>1.5 psia and < 11 psia	> 1,000 gal and <= 40,000 gal	Submerged fill pipe or closed vent system routed to control device
=>1.5 psia and < 11 psia	> 40,000 gal	Internal floating roof or external floating roof with primary seal (any type) and secondary seal or closed vent system routed to control device
=> 11 psia	> 1,000 gal and <= 40,000 gal	Submerged fill pipe and closed vent system routed to control device
=> 11 psia	> 40,000 gal	Submerged fill pipe and closed vent system routed to control device

(c) The owner or operator shall calculate VOC emissions as follows.
(1) Uncontrolled VOC emissions for a fixed roof storage tank must be estimated using the highest 12 consecutive months out of the last five years of production data for the initial determination in accordance with the appropriate compliance date in §115.183 of this title, and one of the following methods. However, if emissions determined using direct measurements or other methods approved by the executive director under subparagraph (A) or (B) of this paragraph are higher than emissions estimated using the default factors or charts in subparagraph (C) or (D) of this paragraph, the higher values must be used.
(A) The owner or operator may make direct measurements using the measuring instruments and methods specified in §115.179 of this title.
(B) The owner or operator may use other test methods or computer simulations approved by the executive director.
(C) The owner or operator may use a factor of 33.3 pounds of VOC per barrel (42 gallons) of condensate produced or 1.6 pounds of VOC per barrel (42 gallons) of oil produced.
(D) For crude oil storage only, the owner or operator may use the chart in Exhibit 2 of the EPA's "Lessons Learned from Natural Gas Star Partners: Installing Vapor Recovery Units on Crude Oil Storage Tanks", October 2003, and assuming that the hydrocarbon vapors have a molecular weight of 34 pounds per pound mole and are 48% by weight VOC.
(2) The VOC potential to emit must be based on the maximum average daily throughput determined for a 30-day period of production prior to the appropriate compliance date listed in §115.183 of this title.
(d) For an external floating roof or internal floating roof storage tank, the following requirements apply.
(1) All openings in an internal floating roof or external floating roof must provide a projection below the liquid surface. Automatic bleeder vents (vacuum breaker vents) and rim space vents are not subject to this requirement.
(2) All openings in an internal floating roof or external floating roof must be equipped with a deck cover. The deck cover must be equipped with a gasket in good operating condition between the cover and the deck. The deck cover must be closed (i.e., no gap of more than 1/8 inch) at all times, except when the cover must be open for access. Automatic bleeder vents (vacuum breaker vents), rim space vents, leg sleeves, and roof drains are not subject to this requirement.
(3) Automatic bleeder vents (vacuum breaker vents) and rim space vents must be equipped with a gasketed lid, pallet, flapper, or other closure device and must be closed (i.e., no gap of more than 1/8 inch) at all times except when required to be open to relieve excess pressure or vacuum in accordance with the manufacturer's design.
(4) Each opening into the internal floating roof for a fixed roof support column may be equipped with a flexible fabric sleeve seal instead of a deck cover.
(5) Any external floating roof drain that empties into the stored liquid must be equipped with a slotted membrane fabric cover that covers at least 90% of the area of the opening or an equivalent control that must be kept in a closed (i.e., no gap of more than 1/8 inch) position at all times except when the drain is in actual use. Stub drains on an internal floating roof storage tank are not subject to this requirement.
(6) There must be no visible holes, tears, or other openings in any seal or seal fabric.
(7) For an external floating roof storage tank, secondary seals must be the rim-mounted type. The seal must be continuous from the floating roof to the tank wall, with the exception of gaps that do not exceed the following specification. The accumulated area of gaps that exceed 1/8 inch in width between the secondary seal and storage tank wall may not be greater than 1.0 square inch per foot of storage tank diameter.
(8) Each opening for a slotted guide pole in an external floating roof storage tank must be equipped with one of the following control device configurations:
(A) a pole wiper and pole float that has a seal or wiper at or above the height of the pole wiper:
(B) a pole wiper and a pole sleeve;
(C) an internal sleeve emission control system;
(D) a retrofit to a solid guide pole system;
(E) a flexible enclosure system; or
(F) a cover on an external floating roof tank.
(9) The external floating roof or internal floating roof must be floating on the liquid surface at all times, except as allowed under the following circumstances:
(A) during the initial fill or refill after the storage tank has been cleaned;
(B) when necessary for preventive maintenance, roof repair, primary seal inspection, or removal and installation of a secondary seal, if product is not transferred into or out of the storage tank, emissions are minimized, and the repair is completed within seven calendar days;
(C) when the storage tank has a storage capacity less than 25,000 gallons;
(D) when the vapors are routed to a control device from the time the storage tank has been emptied to the extent practical or the drain pump loses suction until the floating roof is within 10% by volume of being refloated;
(E) when all VOC emissions from the storage tank, including emissions from floating roof landings, have been included in an emissions limit or cap approved under Chapter 116 of this title (relating to Control of Air Pollution by Permits for New Construction or Modification) prior to March 1, 2013; or
(F) when all VOC emissions from floating roof landings at the regulated entity are less than 25 tons per year.
Adopted by TCEQ June 30, 2021, Effective July 21, 2023
***end Texas Section 115.175 SIP Effective September 14, 2023 (TXd239)***dzs***

§115.176. Alternative Control Requirements.
SIP effective September 14, 2023 (TXd239),
Regulations.gov document EPA-R06-OAR-2021-0525-0003, Adobe file pages 336 to 337
(a) Alternate methods of demonstrating and documenting continuous compliance with the applicable control requirements or exemption criteria in this division may be approved by the executive director in accordance with §115.910 of this title (relating to Availability of Alternate Means of Control) if emission reductions are demonstrated to be substantially equivalent.
(b) The owner or operator of a pneumatic pump at a well site making a determination of technical infeasibility as provided in §115.174(e)(3) of this title (relating to Pneumatic Controller and Pump Control Requirements) shall make a clear demonstration that includes, but is not limited to, the following information:
(1) the specific equipment for which technical infeasibility exists;
(2) the reason such equipment cannot be controlled by any available control option, such as but is not limited to, safety considerations, distance from the control device, pressure losses and differentials in the closed vent system, and the ability of the control device to handle the pump emissions;
(3) data to support reasoning in paragraph (2) of this subsection; and
(4) a certification signed and dated by a qualified professional engineer certifying that the assessment of technical infeasibility prepared was true, accurate, and complete and that knowingly submitting false information is a violation of this subsection.
(c) The owner or operator of a pneumatic controller at a natural gas processing plant making a determination of a functional need as specified in §115.174(e)(4) of this title, must perform the following:
(1) tag the pneumatic controller with a weatherproof tag; and
(2) provide the reason meeting the control requirements cannot be met due to the functional need.
Adopted by TCEQ June 30, 2021, Effective July 21, 2023
***end Texas Section 115.176 SIP Effective September 14, 2023 (TXd239)***dzs***

§115.177. Fugitive Emission Component Requirements.
SIP effective September 14, 2023 (TXd239),
Regulations.gov document EPA-R06-OAR-2021-0525-0003, Adobe file pages 338 to 350
(a) The owner or operator of equipment with fugitive emission components shall create a written plan and maintain such plan in accordance with §115.180 of this title (relating to Recordkeeping Requirements) that details information about the site subject to this section including, but not limited to, the following:
(1) the identification of each fugitive emission component grouping required to be monitored;
(2) the fugitive emission component designated as unsafe-to-monitor or difficult-to-monitor;
(3) the exemptions or exceptions that apply to any fugitive emission component;
(4) the method of monitoring; and
(5) the monitoring survey schedules of the fugitive emission components in paragraph (1) or (2) of this subsection.
(b) The owner or operator shall monitor each affected fugitive emission component and calibrate the hydrocarbon gas analyzer instrumentation in accordance with procedures specified by the United States Environmental Protection Agency (EPA) Method 21 in 40 Code of Federal Regulations (CFR) Part 60, Appendix A-7. The owner or operator may elect to use the alternative work practice in §115.358 of this title for any fugitive emission component, as specified in paragraph (11) of this subsection.
(1) Except as provided in paragraph (5)(C) of this subsection, no component at a natural gas processing plant is allowed to have a volatile organic compounds (VOC) leak for more than five calendar days without a first attempt at repair after the leak is detected and must be repaired no later than 15 calendar days after the leak is found that meets the following:
(A) for pump seals in light-liquid service, a leak definition of 5,000 parts per million by volume (ppmv) for a pump used for any polymerizing monomer and 2,000 ppmv for all other pumps; and
(B) for valves, flanges, connectors, pressure relief devices, pumps in heavy-liquid service, sampling connections, and process drains, a leak definition of 500 ppmv; and.
(C) for compressors, a leak definition of 10,000 ppmv or exuding of process fluid based on sight, smell, or sound.
(2) xcept as provided in paragraph (5)(C) of this subsection, no fugitive emission component at a well site or gathering and boosting station is allowed to have a VOC leak of equal to or greater than 500 ppmv for more than five calendar days without a first attempt at repair after the leak is detected and must be repaired no later than 15 calendar days after the leak is found.
(3) Except as specified in subsection (c) of this section, the owner or operator shall conduct monitoring according to the following schedules.
(A) The owner or operator of a natural gas processing plant shall monitor annually to detect leaks of VOC emissions from all connectors.
(B) Except as provided in subparagraph (E) of this paragraph, the owner or operator shall monitor to detect leaks of VOC emissions from all:
(i) fugitive emission components at gathering and boosting stations quarterly; and
(ii) fugitive emission components at well sites semiannually.
(C) The owner or operator shall monitor quarterly to detect VOC emissions leaks from all:
(i) pump seals at a natural gas processing plant that are not in light-liquid service; and
(ii) fugitive emission components at a natural gas processing plant not specified elsewhere in this paragraph.
(D) The owner or operator shall monitor monthly to detect leaks of VOC emissions at a natural gas processing plant from all:
(i) pressure relief valves in gaseous service;
(ii) pump seals in light-liquid service; and
(iii) accessible fugitive emission components in gas/vapor and light-liquid service, except for connectors.
(E) In addition to monitoring in subparagraphs (B)(i) and (ii) and (D)(i) of this paragraph, the owner or operator shall monitor pressure relief valves within 24 hours of a release.
(F) At a natural gas processing plant, the owner or operator shall visually inspect for indications of dripping liquid each pump in light liquid service weekly. If evidence of a leak is found, the owner or operator shall monitor each leaking pump in accordance with Method 21 in 40 CFR Part 60, Appendix A-7 or the alternative work practice in §115.358 of this title within five calendar days after the leak is detected.
(4) Upon the detection of a leaking fugitive emission component, the
owner or operator shall affix to the leaking component a weatherproof and readily visible tag, bearing an identification number and the date the leak was detected. This tag must remain in place, or be replaced if damaged, until the leaking component is repaired. Tagging of difficult-to-monitor leaking components may be done by reference tagging. The reference tag should be located as close as possible to the leaking component and should clearly identify the leaking component and its location.
(5) When a leak or defect is detected from a fugitive emission component, the owner or operator shall repair the leak or defect as soon as practicable.
(A) A first attempt at repair must be made no later than five calendar days after the leak is detected.
(B) A repair must be completed no later than 15 calendar days after the leak is detected.
(C)If an owner or operator determines and documents that a repair is technically infeasible without a shutdown, vent blowdown at a well site or gathering and boosting station, well shut-in, would be unsafe to repair during operation of the unit, or that emissions resulting from immediate repair would be greater than the total fugitive emissions likely to result from a delay of repair, then the repair is not required to be completed until the end of the next shutdown, vent blowdown at a well site or gathering subparagraph at a well site or gathering and boosting station must be made within two years after the leak is detected.
(D) For the owner or operator using the alternative work practice in §115.358 of this title to monitor fugitive emission components, repair is complete once a monitoring survey using EPA Method 21 in 40 CFR Part 60, Appendix A-7 or the alternative work practice in §115.358 of this title shows no leaking. For the owner or operator using Method 21 in 40 CFR Part 60, Appendix A-7 or audio, visual, or olfactory means to monitor fugitive emission components, repair is complete once the monitoring required under this section shows no leaking. At a well site or gathering and boosting station, this monitoring survey to check that the leak is fixed must be done within 30 days of the repair attempt. At a natural gas processing plant, if a shutdown is needed as specified in subparagraph (C) of this paragraph, the monitoring survey to check that the leak is fixed must be done within 15 days of startup of the process unit.
(6) If the executive director determines that the number of leaks in a process area is excessive, the monitoring schedule in this subsection may be modified to require an increase in the frequency of monitoring in a given process area.
(7) After completion of the required monthly valve monitoring in this subsection for a period of at least two years, the owner or operator of a well site, natural gas processing plant or gathering and boosting station may request in writing to the appropriate regional office that the valve monitoring schedule be revised based on the percent of valves leaking. The percent of valves leaking must be determined by dividing the sum of valves leaking during the current monitoring period and valves for which repair has been delayed by the total number of valves subject to monitoring requirements. The revised monitoring schedule is not effective until a response is received from the executive director. This request must include all data that have been developed to justify the following modifications in the monitoring schedule.
(A) After two consecutive quarterly leak detection periods with the percent of valves leaking equal to or less than 2.0%, an owner or operator may begin to skip one of the quarterly leak detection periods for the valves in gas/vapor and light liquid service.
(B) After five consecutive quarterly leak detection periods with the percent of valves leaking equal to or less than 2.0%, an owner or operator may begin to skip three of the quarterly leak detection periods for the valves in gas/vapor and light liquid service.
(8) All component monitoring must occur when the component is in contact with process material and the process unit is in service. If a unit is not operating during the required monitoring period but a component in that unit is in contact with process fluid that is circulating or under pressure, then that component is considered to be in service and is required to be monitored. Valves must be in gaseous or light liquid service to be considered in the total valve count for alternate valve monitoring schedules of paragraph (7) of this subsection.
(9) Monitored screening concentrations must be recorded for each component in gaseous or light liquid service. Notations such as "pegged," "off scale," "leaking," "not leaking," or "below leak definition" may not be substituted for hydrocarbon gas analyzer results. For readings that are higher than the upper end of the scale (i.e., pegged) even when using the highest scale setting or a dilution probe, a default pegged value of 100,000 ppmv must be recorded. This requirement does not apply to monitoring using an optical gas imaging instrument, which makes emissions visible that may otherwise be invisible to the naked eye, in accordance with §115.358 of this title.
(10) The owner or operator shall check all new connectors for leaks within 30 days of being placed in VOC service by monitoring with a hydrocarbon gas analyzer for components in light-liquid and gas service and by using visual, audio, and/or olfactory means for components in heavy-liquid service. Components that are unsafe-to-monitor or inspect are exempt from this requirement if they are monitored or inspected as soon as possible during times that are safe to monitor.
(11) For any fugitive emission component for which the owner or operator elects to use the alternative work practice in §115.358 of this title, the following provisions apply.
(A) At a natural gas processing plant, the frequency for monitoring components listed in this section must be the frequency determined according to §115.358 of this title. At a well site or gathering and boosting station, the frequency for monitoring components using optical gas imaging is the frequency in paragraph (3) of this subsection.
(B) The alternative monitoring schedules allowed under paragraph (7) of this subsection are not allowed.
(C) At a well site or gathering and boosting station, the requirements in §115.358 of this title, except for the requirements in §115.358(e) and (f) of this title, apply in addition to the appropriate requirements in this section. At a natural gas processing plant, the requirements in §115.358 of this title apply in addition to the applicable requirements in this section.
(D) The owner or operator may still classify a component as unsafe-to-monitor as allowed under subsection (c) of this section if the component cannot safely be monitored using either a hydrocarbon gas analyzer or the alternative work practice. The owner or operator may use either EPA Method 21 in 40 CFR Part 60, Appendix A-7 or the alternative work practice at the monitoring frequency specified in paragraph (3) of this subsection. Any component classified as unsafe-to-monitor under the alternative work practice must be identified as such in the list required in §115.180(7) of this title.
(E) If the executive director determines that there is an excessive number of leaks in any given process area for which the alternative work practice in §115.358 of this title is used, the executive director may require an increase in the frequency of monitoring under the alternative work practice in that process area.
(c) An owner or operator is not required to comply with monitoring frequencies in subsection (b) of this section for any fugitive emission component designated as unsafe-to-monitor or difficult-to-monitor.
(1) Any component, except closed vent systems, designated difficult-to-monitor must be monitored at least once per calendar year. Difficult-to-monitor closed vent system components must be monitored at least once every five years.
(2) Any component designated unsafe-to-monitor must be monitored as frequently as practicable during a time when it is safe-to-monitor, not to exceed the monitoring frequency in subsection (b) of this section.
(3) The number of components designated as difficult-to-monitor may not exceed 3% of total affected components in the same classification (e.g., pumps, valves, flanges, connectors etc.) at the site.
(4) The owner or operator shall inspect all flanges weekly by audio, visual, and olfactory means, excluding flanges that are monitored at least once each calendar year using EPA Method 21 in 40 CFR Part 60, Appendix A-7 and flanges that are difficult-to-monitor and unsafe-to-monitor. Flanges that are difficult-to-monitor and unsafe-to-monitor must be identified in a list made available upon request. If a difficult-to-monitor or an unsafe-to-monitor flange is not considered safe to inspect within the required weekly time frame, then it must be inspected as soon as possible during a time that it is safe to inspect.
(5) Relief valves that are designated as unsafe-to-monitor must be monitored as soon as possible during times that are safe to monitor after any release
event. Relief valves that are designated as difficult-to-monitor must be monitored within 15 days after a release.
Adopted by TCEQ June 30, 2021, Effective July 21, 2023
***end Texas Section 115.177 SIP Effective September 14, 2023 (TXd239)***dzs***

§115.178. Monitoring and Inspection Requirements.
SIP effective September 14, 2023 (TXd239),
Regulations.gov document EPA-R06-OAR-2021-0525-0003, Adobe file pages 350 to 362
(a) At least once each calendar year, an owner or operator shall conduct an audio, visual, and olfactory inspection of each compressor seal cover for defects that may result in air emissions, except as provided in subsection (c) of this section. Defects include, but are not limited to, visible cracks, holes, or gaps in the cover, or between the cover and the separator wall; broken, cracked, or otherwise damaged seals or gaskets on cover devices; and broken or missing hatches, access covers, caps, or other cover devices. Repairs must be made in accordance with subsection (e) of this section.
(b) The following monitoring and inspection requirements apply to closed vent systems routed to a control device, including routing to a process, used to demonstrate compliance with the control requirements of this division, except as specified in subsection (c) of this section. For the purpose of this subsection, a leak is a measured volatile organic compounds (VOC) concentration of equal to or greater than 500 parts per million by volume (ppmv). Defects that could result in air emissions include visible cracks, holes, or gaps in piping; loose connections; liquid leaks; or broken or missing cover devices. Repairs of equipment with a leak or detection of a defect in equipment must be made in accordance with subsection (e) of this section.
(1) The owner or operator shall conduct initial inspection and monitoring by the appropriate compliance date listed in §115.183 of this title (relating to Compliance Schedules), using United States Environmental Protection Agency (EPA) Method 21 in 40 Code of Federal Regulations (CFR) Part 60, Appendix A-7 on all closed vent system components to demonstrate that the closed vent system operates with no leaks. The instrument response factor criteria in EPA Method 21 in 40 CFR Part 60, Section 8.1.1 must be for the average composition of the stream and not for each individual VOC constituent.
(2) The owner or operator shall conduct annual monitoring and inspections following the initial inspection conducted in paragraph (1) of this subsection.
(A) The owner or operator shall conduct an audio, visual, and olfactory inspection on closed vent system joints, seams, or other connections that are permanently or semi-permanently sealed (e.g., a welded joint between two sections of hard piping or a bolted and gasketed ducting flange) for defects that could result in air emissions. For an inspection using EPA Method 21 in 40 CFR Part 60, Appendix A-7, monitoring must be performed to demonstrate that there are no leaks following any time a component is repaired or the closed vent system connection is unsealed.
(B) The owner or operator shall monitor the closed vent system components and connections using EPA Method 21 in 40 CFR Part 60, Appendix A-7, other than those subject to subparagraph (A) of this paragraph, to demonstrate that the closed vent system operates with no leaks.
(3) The owner or operator of a closed vent system routed to a control device, including routing to a process, used to demonstrate compliance with the control requirements of this division, must conduct monitoring using EPA Method 21 in 40 CFR Part 60, Appendix A-7 to demonstrate there are no leaks from the closed vent system.
(A) The instrument response factor criteria in EPA Method 21 in 40 CFR Part 60, Section 8.1.1 must be for the average composition of the stream and not for each individual VOC constituent. For process streams that contain nitrogen, air, or other inert gases that are not VOC, the average stream response factor is calculated on an inert-free basis.
(B) An owner or operator shall calibrate the detection instrument using the procedures specified in EPA Method 21 in 40 CFR Part 60, Appendix A-7 before use on each day the instrument is used.
(C) The following calibration gases must be used.
(i) Zero air must contain less than 10 ppmv hydrocarbon in air.
(ii) The other calibration gases must be mixtures of methane or n-hexane in air, one with a concentration either of less than 10,000 ppmv, and another with a concentration of no more than 2,000 ppmv greater than the leak definition concentration of the equipment monitored. If the design of the monitoring instrument allows for multiple calibration scales, then the lower scale shall be calibrated with a calibration gas that is no higher than 2,000 ppmv above the concentration specified as a leak, and the highest scale shall be calibrated with a calibration gas that is approximately equal to 10,000 ppmv. If only one scale on an instrument will be used during monitoring, the owner or operator is not required to calibrate the scales that will not be used during monitoring that day.
(D) The owner or operator shall follow EPA Method 21 in 40 CFR Part 60, Appendix A-7 to adjust instrument readings if choosing to account for the background VOC level.
(E) Using the following parameters, the owner or operator shall determine if a potential leak interface operates with no detectable emissions. A potential leak interface is determined to operate with no detectable VOC emissions if the organic concentration value is less than 500 ppmv.
(i) If an owner or operator chooses not to adjust the detection instrument readings for the background VOC concentration level, then the maximum organic concentration value measured by the detection instrument must be compared to the 500 ppmv value for the potential leak interface.
(ii) If an owner or operator chooses to adjust the detection instrument readings for the background VOC concentration level, an owner or operator shall compare the value of the arithmetic difference between the maximum organic concentration value measured by the instrument and the background organic concentration value with the 500 ppmv value for the potential leak interface.
(c) Closed vent system components and compressor seal covers that are designated as unsafe-to-monitor or difficult-to-monitor are not subject to the inspection and monitoring frequency in subsection (b) of this section. The monitoring methods of the components and covers that apply in subsections (a) and (b) of this section apply to the components in this subsection.
(1) Unsafe-to-monitor components must be identified in a list in accordance with the requirements in §115.180 of this title (relating to Recordkeeping Requirements). If an unsafe-to-monitor component is not considered safe to monitor within a calendar year, then it must be monitored as soon as possible during times that are safe to monitor.
(2) Difficult-to-monitor components must be identified in a list in accordance with the requirements in §115.180 of this title. A difficult-to-monitor component must be inspected at least once every five years.
(d) Upon the detection of a leak, the owner or operator shall affix to the leaking component a weatherproof and readily visible tag bearing an identification number and the date the leak was detected. This tag must remain in place, or be replaced if damaged, until the leaking component is repaired. Tagging of difficult-to-monitor leaking components may be done by reference tagging. The reference tag should be located as close as possible to the leaking component and should clearly identify the leaking component and its location.
(e) The owner or operator shall repair a leak or defect as soon as practicable and shall make a first attempt to repair a leak or defect no later than five calendar days after the leak or defect is found. The component must be repaired no later than 15 calendar days after the leak or defect is found, except if a delay of repair is needed. If parts are unavailable, repair may be delayed if parts are ordered promptly. The repair must be completed within five days of receipt of the required parts. Repair may be delayed until the next shutdown if the repair of the component would require a shutdown that would create more total VOC emissions than the repair would eliminate, but the repair must be completed by the end of the next shutdown. A repair is complete once an EPA Method 21 or audio, visual, and olfactory inspection, as appropriate, under subsection (b)(2) or (3) of this section is conducted showing no leak or defect.
(f) The owner or operator shall install and maintain monitors to measure operational parameters of any control device installed to meet applicable control requirements of this division. Such monitors must be sufficient to demonstrate proper functioning of those devices to design specifications.
(1) For a direct-flame incinerator, the owner or operator shall continuously monitor the exhaust gas temperature immediately downstream of the device.
(2) For a condensation system, the owner or operator shall continuously monitor the outlet gas temperature to ensure the temperature is below the manufacturer's recommended operating temperature for controlling the VOC vapors routed to the device.
(3) For a carbon adsorption system or carbon adsorber, as defined in §101.1 of this title (relating to Definitions), the owner or operator shall, as applicable:
(A) continuously monitor the exhaust gas VOC concentration of a carbon adsorption system that regenerates the carbon bed directly to determine breakthrough, which for the purpose of this paragraph, is defined as a measured VOC concentration exceeding 100 ppmv above background expressed as methane; or
(B) switch the vent gas flow to fresh carbon at a regular predetermined time interval for a carbon adsorber or carbon adsorption system that does not regenerate the carbon directly. The time interval must be less than the carbon replacement interval determined by the maximum design flow rate and the VOC concentration in the gas stream vented to the carbon adsorption system or carbon adsorber.
(4) For a catalytic incinerator, the owner or operator shall continuously monitor the inlet and outlet gas temperature.
(5) For a vapor recovery unit, the owner or operator shall continuously monitor at least one of the following operational parameters:
(A) run-time of the compressor or motor in a vapor recovery unit;
(B) total volume of recovered vapors; or
(C) other parameters sufficient to demonstrate proper functioning to design specifications.
(6) For a control device not listed in this subsection, the owner or operator shall continuously monitor one or more operational parameters sufficient to demonstrate proper functioning of the control device to design specifications.
(g) The following inspection requirements apply to storage tanks subject to the control requirements in this division.
(1) For an internal floating roof storage tank, the internal floating roof and the primary seal and the secondary seal (if one is in service) must be visually inspected through a fixed roof inspection hatch at least once every 12 months.
(A) If the internal floating roof is not resting on the surface of the VOC inside the storage tank and is not resting on the leg supports; if liquid has accumulated on the internal floating roof; if the seal is detached; if there are holes or tears in the seal fabric; or if there are visible gaps between the seal and the wall of the storage tank, within 60 days of the inspection the owner or operator shall repair the items or shall empty and degas the storage tank in accordance with Subchapter F, Division 3 of this chapter (relating to Degassing of Storage Tanks, Transport Vessels, and Marine Vessels).
(B) If a failure identified in subparagraph (A) of this paragraph cannot be repaired within 60 days and the storage tank cannot be emptied within 60 days, the owner or operator may submit written requests for up to two extensions of up to 30 additional days each to the appropriate regional office. The owner or operator shall submit a copy to any local air pollution control program with jurisdiction. Each request for an extension must include a statement that alternate storage capacity is unavailable and a schedule that will assure that the repairs will be completed as soon as possible.
(2) For an external floating roof storage tank, the secondary seal gap must be physically measured at least once every 12 months to ensure compliance with §115.175 this title (relating to Storage Tank Control Requirements).
(A) If the secondary seal gap exceeds the limitations specified by §115.175(d) of this title, within 60 days of the inspection the owner or operator shall repair the items or shall empty and degas the storage tank in accordance with Subchapter F, Division 3 of this chapter.
(B) If a failure identified in subparagraph (A) of this paragraph cannot be repaired within 60 days and the storage tank cannot be emptied within 60 days, the owner or operator may submit written requests for up to two extensions of up to 30 additional days each to the appropriate regional office. The owner or operator shall submit a copy to any local air pollution control program with jurisdiction. Each request for an extension must include a statement that alternate storage capacity is unavailable and a schedule that will assure that the repairs will be completed as soon as possible.
(3) If the storage tank is equipped with a mechanical shoe or liquid-mounted primary seal, compliance with §115.175 of this title can be determined by visual inspection.
(4) For an external floating roof storage tank, the secondary seal must be visually inspected at least once every six months to ensure compliance with §115.175 of this title.
(A) If the external floating roof is not resting on the surface of the VOC inside the storage tank and is not resting on the leg supports; if liquid has accumulated on the external floating roof; if the seal is detached; if there are holes or tears in the seal fabric; or if there are visible gaps between the seal and the wall of the storage tank, within 60 days of the inspection the owner or operator shall repair the items or shall empty and degas the storage tank in accordance with Subchapter F, Division 3 of this chapter.
(B) If a failure identified in subparagraph (A) of this paragraph cannot be repaired within 60 days and the storage tank cannot be emptied within 60 days, the owner or operator may submit written requests for up to two extensions of up to 30 additional days each to the appropriate regional office. The owner or operator shall submit a copy to any local air pollution control program with jurisdiction. Each request for an extension must include a statement that alternate storage capacity is unavailable and a schedule that will assure that the repairs will be completed as soon as possible.
(5) The owner or operator shall conduct an audio, visual, and olfactory inspection at least once per month, separated by at least 14 calendar days, of a control device used to control the VOC emissions from a storage tank.
(6) The owner or operator shall inspect and repair all closure devices not connected to a control device according to the schedule in this paragraph.
(A) The owner or operator shall conduct an audio, visual, and olfactory inspection of each closure device not connected to a vapor recovery unit or other vapor control device to ensure compliance with §115.175(a)(1)(A) of this title. The inspection must occur when liquids are not being added to or unloaded from the tank. If the owner or operator finds the closure device open for reasons not allowed in §115.175(a)(1)(A) of this title, the owner or operator shall attempt to close the device during the inspection. The inspection must occur before the end of one business day after each opening of a thief or access hatch for sampling or gauging, and before the end of one business day after each unloading event. If multiple events occur on a single day, a single inspection within one business day after the last event is sufficient.
(B) Once per calendar quarter, the owner or operator shall conduct an audio, visual, and olfactory inspection of all gaskets and vapor sealing surfaces of each closure device not connected to a vapor recovery unit or other control device to ensure compliance with §115.175(a)(1)(B) of this title. If an improperly sealed closure device is found, the owner or operator shall follow repair requirements in accordance with §115.175(a)(1)(D) of this title. For the purpose of this subparagraph, a repair is complete if the closure device no longer exudes process gasses based on audio, visual, and olfactory means.
(h)This section does not apply to fugitive emission components required to comply with §115.177 of this title (relating to Fugitive Emission Component Requirements).
Adopted by TCEQ June 30, 2021, Effective July 21, 2023
***end Texas Section 115.178 SIP Effective September 14, 2023 (TXd239)***dzs***

§115.179. Approved Test Methods and Testing Requirements.
SIP effective September 14, 2023 (TXd239),
Regulations.gov document EPA-R06-OAR-2021-0525-0003, Adobe file pages 362 to 372
(a) Compliance with the requirements in this division must be determined by applying the following test methods, as appropriate.
(1) United States Environmental Protection Agency (EPA) Method 1 or 1A in 40 Code of Federal Regulations (CFR) Part 60, Appendix A-1 must be used to select sampling sites. The references to particulate sampling do not apply for purposes of using these methods in this division.
(2) EPA Method 2, 2A, 2C, or 2D in 40 CFR Part 60, Appendix A-2 must be used to determine the gas volumetric flow rate.
(3) EPA Method 3A or 3B, in 40 CFR Part 60, Appendix A-2, ASTM D6522-00 (Reapproved 2005), or American National Standards Institute/American Society of Mechanical Engineers Performance Test Codes (ANSI/ASME PTC) 19.10-1981, Part 10 (manual portion only) must be used to determine the oxygen concentration.
(4) EPA Method 4 in 40 CFR Part 60, Appendix A-3 must be used for determining the stack gas moisture content.
(5) EPA Method 18 in 40 CFR Part 60, Appendix A-6 must be used for determining the concentrations of methane and ethane.
(6) EPA Method 21 in 40 CFR Part 60, Appendix A-7 must be used for determining volatile organic compound (VOC) leaks.
(7) EPA Method 22 in 40 CFR Part 60, Appendix A-7, Section 11 must be used for determining visible emissions.
(8) EPA Method 25A in 40 CFR Part 60, Appendix A-7 must be used for determining total gaseous organic concentrations using flame ionization.
(9) Minor modifications to either test methods or monitoring methods may be approved by the executive director. Test methods other than those specified in paragraphs (1) - (8) of this subsection may be used if approved by the executive director and validated by EPA Method 301 (40 CFR Part 63, Appendix A). For the purposes of this paragraph, substitute "executive director" each place that EPA Method 301 references "administrator."
(b)The following procedures must be used to demonstrate compliance with the control requirements in this division for a control device, other than a flare and routing to a process, and as appropriate.
(1) The owner or operator of a combustion control device tested to comply with the 275 parts per million by volume (ppmv) outlet VOC limit shall establish a correlation between firebox or combustion chamber temperature and the VOC performance level. The owner or operator shall also establish minimum and maximum temperatures or other operating parameter that will be continuously monitored to demonstrate compliance with the control device requirements in this division.
(2) The following testing requirements apply to control devices used to demonstrate compliance with the control requirements of this division. Each performance test must consist of a minimum of three test runs, and each run must be at least one hour long.
(A) The owner or operator shall conduct an initial control device performance test by the compliance date in §115.183 of this title (relating to Compliance Schedules) using the test methods in this subsection.
(B) The owner or operator shall conduct a periodic performance test no later than 60 months after the previous performance test. For any modification of a closed vent system, control device, or equipment regulated in this division that could reasonably be expected to decrease the control efficiency of the control device, such device must be retested within 60 days of the modification.
(3) In lieu of periodic performance testing required in paragraph (2) of this subsection, the owner or operator may complete a design analysis to satisfy compliance with the control requirements of this division. The owner or operator shall determine through monitoring the parameters sufficient to determine proper functioning of the control device is met, as required in the monitoring requirements in §115.178(f) of this title (relating to Monitoring and Inspection Requirements).
(A) For a vapor recovery unit or condenser, the design analysis criteria evaluated must include an analysis of the vent stream composition, speciated VOC concentrations, flowrate, relative humidity, and temperature. In addition, the design analysis must establish the design outlet VOC concentration level, design average temperature of the vapor recovery unit or condenser exhaust vent stream, and the design inlet and outlet average temperatures of the coolant fluid.
(B) For a regenerable carbon adsorption system, a design analysis must include the design exhaust vent stream VOC concentration level, adsorption cycle time, number and capacity of carbon beds, type and working capacity of activated carbon used for the carbon beds, design total regeneration stream flow over the period of each complete carbon bed regeneration cycle, design carbon bed temperature after regeneration, design carbon bed regeneration time, and design service life of the carbon.
(C) For a non-regenerable carbon adsorption system (such as a carbon canister), the design analysis must include the vent stream composition, VOC constituent concentrations, flowrate, relative humidity, and temperature, and must establish the design exhaust vent stream VOC level, capacity of the carbon bed, type and working capacity of activated carbon used for the carbon bed, and design carbon replacement interval based on the total carbon working capacity of the control device and source operating schedule. In addition, these systems must incorporate dual carbon canisters in case of emission breakthrough occurring in one canister.
(D) For a combustion control device, other than a flare, the design analysis must identify each existing, or derived, control device design parameter including waste stream and supplemental fuel flowrates, mixing characteristics, composition, net heating value, combustion zone temperature, residence time, excess oxygen and relative humidity. The analysis must compare these control device design parameters with actual control device operating data, for a minimum of the prior two years, to ensure the control device is being operated as designed. A physical inspection of the combustion device is required as part of this analysis to assess whether equipment wear is present that will result a significant reduction in operating efficiency or require prompt maintenance.
(4) In lieu of performing control device testing required in paragraph (2) of this subsection, the owner or operator may use data from a performance test conducted by the manufacturer on the same control device model that is used to comply with control requirements in this division. The owner or operator shall comply with the monitoring requirements in §115.178(f) of this title, and the data in the manufacturer's report must be sufficient to determine proper functioning of the control device as required in the monitoring requirements in §115.178(f) of this title.
(A) The manufacturer's guarantee must demonstrate that the specific model of control device meets the 95% control efficiency required in the control requirements of this division.
(B) The control device must be equipped with an inlet gas flow rate meter. Control devices, other than combustion control devices, must have a separate outlet gas flow rate meter.
(C) The owner or operator of a control device model tested under this paragraph shall maintain the test report in accordance with §115.180 of this title (relating to Recordkeeping Requirements). The test report must include, but is not limited to, all information required under 40 CFR §60.5413a(d)(12) (as amended September 15, 2020 (85 FR 57447)) that is applicable to the test conducted.
(c) The owner or operator shall calculate the control efficiency of a control device using the test results from subsection (b) of this section and the following procedure.
(1) The owner or operator shall use EPA methods specified in subsection (a)(1) or (2) of this section to determine the flow rate of the inlet to outlet to determine the mass rate; EPA Method 25A in 40 CFR Part 60, Appendix A-7; EPA Method 4 in 40 CFR Part 60, Appendix A-3 (to convert the EPA Method 25A results to a dry basis); and equations 1 and 2 to calculate percent reduction efficiency to determine compliance with control device VOC reduction efficiency limits in this division.

Figure: 30 TAC §115.179(c)(1)

Equation 1.

E_i= K2 _* Ci _* Mp _* Qi

E_o = K2 _* Co _*Mp_*Qo

Where:
E_i = Mass rate of volatile organic compound (VOC) at the inlet of the control device, on a dry basis, kilograms per hour.

E_o = Mass rate of VOC at the outlet of the control device, on a dry basis, kilograms per hour.

K2 = Constant, 2.494 × 10^-6 parts per million (gram-mole per standard cubic meter) (kilogram/gram) (minute/hour), where standard temperature is 20°Celsius.

Ci = Concentration of VOC, as propane, of the gas stream as measured by the United States Environmental Protection Agency (EPA) Method 25A in 40 Code of Federal Regulations (CFR) Part 60, Appendix A-7, at the inlet of the control device, on a dry basis, parts per million by volume (ppmv).

Co = Concentration of VOC, as propane, of the gas stream as measured by EPA Method 25A in 40 CFR Part 60, Appendix A-7 at the outlet of the control device, on a dry basis, ppmv.

Mp = Molecular weight of propane, 44.1 gram/gram-mole.

Qi = Flowrate of gas stream at the inlet of the control device, dry standard cubic meter per minute.

Qo = Flowrate of gas stream at the outlet of the control device, dry standard cubic meter per minute.

Equation 2.

(E_i– E_o)
R_cd ---------- * 100%
E_i

Where:

R_cd = Control efficiency of control device, percent.

E_i = Mass rate of VOC at the inlet to the control device as calculated in kilograms per hour from the equation for E_i in this table.

E_o = Mass rate of VOC at the outlet of the control device, as calculated in kilograms per hour from the equation for E_o in this table.

(2) The owner or operator shall use EPA Method 25A in 40 CFR Part 60, Appendix A-7 to determine the exhaust gas concentration of total organic carbon in ppmv for the purpose of determining compliance with control device exhaust gas ppmv concentration limits in this division.
(A) The owner or operator may elect to conduct EPA Method 18 sampling simultaneously with EPA Method 25A in 40 CFR Part 60, Appendix A-7 sampling to quantify methane and ethane concentrations and subtract the combined values to derive a total VOC ppmv concentration. If using this option, the owner or operator shall take either an integrated sample or a minimum of four grab samples per hour at approximately equal intervals in time, such as 15-minute intervals during the run.
(B) The owner or operator shall use the emission rate correction factor for excess air, integrated sampling and analysis procedures of EPA Method 3A or 3B in 40 CFR Part 60, Appendix A-2; American Society for Testing and Materials (ASTM) D6522-00 (Reapproved 2005); or ANSI/ASME PTC 19.10-1981, Part 10 (manual portion only), to determine the oxygen concentration. The samples must be taken during the same time as the EPA Method 25A and EPA Method 18 samples. The owner or operator shall correct the VOC concentration for percent oxygen as provided in the following equation:

Figure: 30 TAC §115.179(c)(2)(B)

17.9
C_c = C_{m *} (---------------)
(20.9 – %O₂)
Where:

C_c = Total Organic Compounds (TOC) concentration, as propane, corrected to 3 percent oxygen, parts per million by volume (ppmv) on a wet basis.

C_m = TOC concentration, as propane, ppmv on a wet basis.

%O₂ = Concentration of oxygen, percent by volume as measured, wet.

(3) The owner or operator of a combustion control device tested under subsection (b)(3)(C) of this section electing to comply with the 275 ppmv outlet limit in the control requirements of this division shall establish a correlation between firebox or combustion chamber temperature and the VOC emissions level. The owner or operator shall also establish minimum and maximum temperatures or other operating parameters that will be continuously monitored to demonstrate the VOC concentration is equal to or less than 275 ppmv as measured at the outlet of the device.
(d) A flare used to comply with the control requirements in this division must meet the requirements of 40 CFR §60.18(b) -(f) (as amended through December 22, 2008 (73 FR 78209)).
(e) The owner or operator of a control device, other than a flare or routing to a process, must perform a visible emissions test in accordance with EPA Method 22 in 40 CFR Part 60, Appendix A-7, Section 11 at least once every calendar month, separated by at least 15 days between each test. Devices failing the visible emissions test must comply with the following.
(1) The owner or operator shall follow the manufacturer's repair instructions, if available, or best combustion engineering practices for any necessary repairs.
(2) Upon returning to operation from maintenance or repair activity, each device must pass an EPA Method 22 visual observation test (40 CFR Part 60, Appendix A7, Section 11) as described in this subsection.
(3) The owner or operator shall operate a control device following the manufacturer's written operating instructions, procedures and maintenance schedule to ensure good air pollution control practices for minimizing emissions.
(f) A control device for which a performance test is waived in accordance with 40 CFR §60.8(b) (as amended August 30, 2016 (81 FR 59809)) is exempt from the testing requirements of this section.
Adopted by TCEQ June 30, 2021, Effective July 21, 2023
***end Texas Section 115.179 SIP Effective September 14, 2023 (TXd239)***dzs***

§115.180. Recordkeeping Requirements.
SIP effective September 14, 2023 (TXd239),
Regulations.gov document EPA-R06-OAR-2021-0525-0003, Adobe file pages 372 to 379.
Records required in this section must be maintained for five years onsite or at the nearest local field office and must be made available upon request to representatives of the executive director, the United States Environmental Protection Agency, or any local air pollution control agency having jurisdiction in the area. Results must be made available for review within 24 hours.
(1) The owner or operator shall maintain records of any operational parameter monitoring required in §115.178(f) of this title (relating to Monitoring and Inspection Requirements). Such records must be sufficient to demonstrate proper functioning of those devices to design specifications and must include, but are not limited to, the following.
(A) For a direct-flame incinerator, the owner or operator shall continuously record the exhaust gas temperature immediately downstream of the device.
(B) For a condensation system, the owner or operator shall continuously record the outlet gas temperature to ensure the temperature is below the manufacturer's recommended operating temperature for controlling the volatile organic compounds (VOC) vapors routed to the device.
(C) For a carbon adsorption system or carbon adsorber, the owner or operator shall:
(i) continuously record the exhaust gas VOC concentration of any carbon adsorption system monitored according to §115.178(f)(3)(A) of this title; or
(ii) record the date and time of each switch between carbon containers and the method of determining the carbon replacement interval if the carbon adsorption system or carbon adsorber is switched according to §115.178(f)(3)(B) of this title.
(D) For a catalytic incinerator, the owner or operator shall continuously record the inlet and outlet gas temperature.
(E) For a vapor recovery unit, the owner or operator shall maintain records of the continuous operational parameter monitoring required in §115.178(f)(5) of this title.
(F) For any other control device, the owner or operator shall maintain records of the continuous operational parameter monitoring required in §115.178(f)(6) of this title sufficient to demonstrate proper functioning of the control device to design specifications.
(2) The owner or operator claiming an exemption in §115.172 of this title (relating to Exemptions) shall maintain records sufficient to demonstrate continuous compliance with the applicable exemption criteria.
(3) The owner or operator shall maintain the results of any control device testing conducted in accordance with §115.179 of this title (relating to Approved Test Methods and Testing Requirements) including, at a minimum, the following information:
(A) the date of each periodic performance test;
(B) the test method(s) used to conduct the test;
(C) the equipment type listed in §115.170 of this title (relating to Applicability) controlled by the device; and
(D) the report showing the testing results of the control device.
(4) Except for fugitive emission components, the owner or operator shall maintain records of the results of each inspection, monitoring survey other than monitoring specified in §115.178(f) of this title, and repair required in this division, including the following items:
(A) the date of the inspection;
(B) an identifier of each piece of leaking equipment;
(C) the tag information required by the owner or operator in accordance with §115.178(d) of this title, if different than the information in subparagraph (B) of this paragraph;
(D) the status of the cover or closure device during inspection;
(E) the date on which attempts at repair, if necessary, were made, the date on which a repair was made, and an explanation of the reasons, if repair was delayed;
(F) the equipment type and associated designation (e.g, difficult-to-monitor), if appropriate, listed in §115.170 of this title;
(G) the amount of time a cover or closure device was open since the last inspection for reasons not allowed in the control requirements of §115.175 of this title (relating to Storage Tank Control Requirements);
(H) screening concentration results from monitoring using a hydrocarbon analyzer; and
(I) the results of monitoring following repair required in §115.178(b)(2)(A) or (e) of this title.
(5) The owner or operator of a reciprocating compressor subject to §115.173(3)(D)
or (E) of this title (relating to Compressor Control Requirements) shall document the following information to demonstrate compliance with the appropriate control requirement:
(A) the continuously recorded number of hours the reciprocating compressor operated between each rod packing replacement, restarting the number of hours after the date of each replacement, as necessary; and
(B) the date and time of each reciprocating compressor rod packing replacement and the number of months between each replacement, as necessary.
(6) The owner or operator of a pneumatic device shall:
(A) maintain records documenting that a control device does not exist onsite as of the appropriate date of compliance in §115.183 of this title (relating to Compliance Schedules) if complying with §115.174(e)(2) of this title (relating to Pneumatic Controller and Pump Control Requirements); and
(B) maintain records documenting that maintenance is performed as
required by §115.174(f) of this title.
(7) The owner or operator shall maintain records of audio, visual, and olfactory inspections and monitoring surveys required for any fugitive emission component including the following:
(A) instrument monitoring survey dates;
(B) monitoring results;
(C) a list of repairs needed, the date on which attempts at repair were made, explanation of the reasons for delay of repair, the date on which a repair was made, and unit shutdowns;
(D) a list of fugitive emission components that are difficult-to-monitor and unsafe-to-monitor;
(E) required electronic photos to document optical gas imaging monitoring surveys;
(F) fugitive emission component monitoring plan required in §115.177(a) of this title (relating to Fugitive Emission Component Requirements);
(G) documentation for wells with the volume of gas at standard temperature and pressure that is produced from a volume of oil when depressurized to standard temperature and pressure (i.e., a gas/oil ratio) of less than 300 standard cubic feet per stock barrel of crude oil produced; and.
(H) if using the alternative work practice in §115.358 of this title (relating to Alternative Work Practice), the records required by §115.356(4)(A) -(I) of this title (relating to Recordkeeping Requirements).
(8) An owner or operator shall maintain a report with the information specified in this paragraph. Every five years from the previous completion date, the report information must be updated, as necessary, and maintained. The information must include, at a minimum, the following:
(A) the regulated entity name and number, if a regulated entity number exists for the entity;
(B) a description of and the identity of, which may include a clearly labeled diagram, each piece of equipment and fugitive emission component groupings;
(C) the initial compliance status of each piece of equipment and fugitive emission component grouping, including functional needs for pneumatic controllers at a natural gas processing plant specified in §115.174(e)(4) of this title and technical infeasibility issues with controlling pneumatic pumps at a well site specified in §115.174(e)(5) of this title; and
(D) an assessment and certification by the owner or operator that any closed vent system used to route emissions to a control device, including routing to a process, is of sufficient design and capacity to ensure that volatile organic compounds emissions are routed to the control device.
***end Texas Section 115.180 SIP Effective September 14, 2023 (TXd239)***dzs***

§115.181. Reporting Requirements.
SIP effective September 14, 2023 (TXd239),
Regulations.gov document EPA-R06-OAR-2021-0525-0003, Adobe file pages 380 to 380.
An owner or operator shall notify the appropriate Texas Commission on Environmental Quality regional office at least 45 days in advance and allow a representative of the executive director to witness the testing of a control device conducted in accordance with §115.179(c) of this title (relating to Approved Test Methods and Testing Requirements).
Adopted by TCEQ June 30, 2021, Effective July 21, 2023
***end Texas Section 115.181 SIP Effective September 14, 2023 (TXd239)***dzs***

§115.183. Compliance Schedules.
SIP effective September 14, 2023 (TXd239),
Regulations.gov document EPA-R06-OAR-2021-0525-0003, Adobe file pages 380 to 381.
(a) The owner or operator of a piece of equipment that meets the applicability in §115.170 of this title (relating to Applicability) and is subject to a requirement of this division shall be in compliance as soon as practicable, but no later than January 1, 2023.
(b) For an owner or operator subject to this division as of January 1, 2023, the recordkeeping required by §115.180(8) of this title (relating to Recordkeeping Requirements) must be completed no later than March 31, 2023.
(c) An owner or operator who becomes subject to the requirements of this division on or after the date specified in subsection (a) of this section shall comply with the requirements in this division no later than 60 days after becoming subject. Recordkeeping required under §115.180(8) of this title must be complied with no later than 30 days after compliance with the division is achieved.
(d) The owner or operator of a storage tank subject to the requirements in Division 1 of this subchapter (relating to the Storage of Volatile Organic Compounds) shall remain subject to that division until compliance with the requirements in this division are achieved, but not later than January 1, 2023.
(e) The owner or operator of a fugitive emission component at a natural gas processing plant as defined in §115.10 of this title (relating to Definitions), subject to the requirements of Subchapter D, Division 3 of this chapter (relating to Fugitive Emission Control in Petroleum Refining, Natural Gas/Gasoline Processing, and Petrochemical Processes in Ozone Nonattainment Areas) shall remain subject to that division until compliance with the requirements in this division are achieved, but not later than January 1, 2023.
(f) Upon the date the owner or operator can no longer claim the exceptions in §115.174(e) of this title (relating to Pneumatic Controller and Pump Control Requirements), the owner or operator shall comply with the appropriate control requirement within 60 days.
Adopted by TCEQ June 30, 2021, Effective July 21, 2023
***end Texas Section 115.180 SIP Effective September 14, 2023 (TXd239)***dzs***

***end Texas Chapter 115, Subchapter B, Division 7 SIP Effective September 14, 2023 (TXd239)***dzs***

5B7 DIVISION 7: OIL AND NATURAL GAS IN OZONE NONATTAINMENT AREAS, SIP effective September 14, 2023 (TXd239)

Air Quality Implementation Plans