§ 129.137. Fugitive emissions components.
(a) Applicability. This section applies to the owner or operator of a fugitive emissions component subject to § 129.131(a)(5) (relating to general provisions and applicability), located at one or more of the following:
(1) A conventional well site.
(2) A natural gas gathering and boosting station.
(3) A natural gas processing plant.
(b) Average production calculation procedure for a well site. Beginning on or before January 1, 2023:
(1) The owner or operator of a well site subject to subsection (a)(1) shall calculate the average production in barrels of oil equivalent per day of the well site using the previous 12 calendar months of operation as reported to the Department and thereafter as specified in subsection (c)(4) for the previous calendar year. The owner or operator shall do the following:
(i) For each well at the well site with production reported to the Department:
(A) Record the barrels of oil produced for each active well.
(B) Convert the natural gas production for each active well to equivalent barrels of oil by dividing the standard cubic feet of natural gas produced by 6,000 standard cubic feet per barrel of oil equivalent.
(C) Convert the condensate production for each active well to equivalent barrels of oil by multiplying the barrels of condensate by 0.9 barrels of oil equivalent per barrel of condensate.
(ii) Calculate the total production for each active well, in barrels of oil equivalent, by adding the results of subparagraph (i)(A)—(C) for each active well.
(iii) Sum the results of subparagraph (ii) for all active wells at the well site and divide by 365 or 366 days for the previous 12 calendar months or the previous calendar year, as applicable.
(2) If the owner or operator does not know the production of an individual well at the well site, the owner or operator shall comply with subsection (c)(2).
(c) Requirements for a conventional well site.
(1) For a well site consisting of only oil wells, the owner or operator shall:
(i) Determine the GOR of the oil well site using generally accepted methods.
(ii) If the GOR of the oil well site is less than 300 standard cubic feet of gas per barrel of oil produced, maintain the records under § 129.140(g)(1) (relating to recordkeeping and reporting).
(iii) If the GOR of the oil well site is equal to or greater than 300 standard cubic feet of gas per barrel of oil produced, meet the requirements of paragraph (2) or paragraph (3) based on the results of subsection (b)(1).
(2) For a well site producing, on average, equal to or greater than 15 barrels of oil equivalent per day, with at least one well producing, on average, equal to or greater than 15 barrels of oil equivalent per day, the owner or operator shall:
(i) Conduct an initial AVO inspection on or before January 31, 2023, with monthly inspections thereafter separated by at least 15 calendar days but not more than 45 calendar days.
(ii) Conduct an initial LDAR inspection program on or before January 31, 2023, with quarterly inspections thereafter separated by at least 60 calendar days but not more than 120 calendar days using one or more of the following:
(A) OGI equipment.
(B) A gas leak detector that meets the requirements of EPA Method 21.
(C) Another leak detection method approved by the Department.
(3) For a well site producing, on average, equal to or greater than 15 barrels of oil equivalent per day, and at least one well producing, on average, equal to or greater than 5 barrels of oil equivalent per day but less than 15 barrels of oil equivalent per day, the owner or operator shall:
(i) Conduct an initial AVO inspection on or before January 31, 2023, with monthly inspections thereafter separated by at least 15 calendar days but not more than 45 calendar days.
(ii) Conduct an initial LDAR inspection program on or before May 1, 2023, with annual inspections thereafter separated by at least 335 calendar days but not more than 395 calendar days using one or more of the following:
(A) OGI equipment.
(B) A gas leak detector that meets the requirements of EPA Method 21.
(C) Another leak detection method approved by the Department.
(4) The owner or operator of a producing well site shall calculate the average production of the well site under subsection (b) for the previous calendar year not later than February 15 and may adjust the frequency of the required LDAR inspection as follows:
(i) If two consecutive calculations show reduced production, the owner or operator may adopt the requirements applicable to the reduced production level.
(ii) If a calculation shows higher production, the owner or operator shall adopt the requirements applicable to the higher production level immediately.
(5) The owner or operator of a well site subject to paragraph (3) may submit to the appropriate Department Regional Office a request, in writing, for an exemption from the requirements of paragraph (3)(ii).
(i) The written request must include the following:
(A) Name and location of the well site.
(B) A demonstration that the requirements of paragraph (3)(ii) are not technically or economically feasible for the well site.
(C) Sufficient methods for demonstrating compliance with all applicable standards or regulations promulgated under the Clean Air Act or the Act.
(D) Sufficient methods for demonstrating compliance with this section, § § 129.131—129.136 and 129.138—129.140.
(ii) The Department will review the complete written request submitted in accordance with subparagraph (i) and approve or deny the request in writing.
(iii) The Department will submit each exemption determination approved under subparagraph (ii) to the Administrator of the EPA for approval as a revision to the SIP. The owner or operator shall bear the costs of public hearings and notifications, including newspaper notices, required for the SIP submittal.
(iv) The owner or operator of the well site identified in subparagraph (i)(A) shall remain subject to the requirements of paragraphs (1), (3)(i) and (4).
(d) Requirements for a shut-in conventional well site. The owner or operator of a conventional well site that is temporarily shut-in is not required to perform an LDAR inspection of the well site until one of the following occurs, whichever is first:
(1) Sixty days after the conventional well site is put into production.
(2) The date of the next required LDAR inspection after the conventional well site is put into production.
(e) Requirements for a natural gas gathering and boosting station or a natural gas processing plant. The owner or operator of a natural gas gathering and boosting station or a natural gas processing plant shall conduct the following:
(1) An initial AVO inspection on or before January 31, 2023, with monthly inspections thereafter separated by at least 15 calendar days but not more than 45 calendar days.
(2) An initial LDAR inspection program on or before January 31, 2023, with quarterly inspections thereafter separated by at least 60 calendar days but not more than 120 calendar days using one or more of the following:
(i) OGI equipment.
(ii) A gas leak detector that meets the requirements of EPA Method 21.
(iii) Another leak detection method approved by the Department.
(f) Requirements for extension of the LDAR inspection interval. The owner or operator of an affected facility may request, in writing, an extension of the LDAR inspection interval from the Air Program Manager of the appropriate Department Regional Office.
(g) Fugitive emissions monitoring plan. The owner or operator shall develop, in writing, an emissions monitoring plan that covers the collection of fugitive emissions components at the subject facility within each company-defined area. The written plan must include the following elements:
(1) The technique used for determining fugitive emissions.
(2) A list of fugitive emissions detection equipment, including the manufacturer and model number, that may be used at the facility.
(3) A list of personnel that may conduct the monitoring surveys at the facility, including their training and experience.
(4) The procedure and timeframe for identifying and fixing a fugitive emissions component from which fugitive emissions are detected, including for a component that is unsafe-to-repair.
(5) The procedure and timeframe for verifying fugitive emissions component repairs.
(6) The procedure and schedule for verifying the fugitive emissions detection equipment is operating properly.
(i) For OGI equipment, the verification must be completed as specified in subsection (h).
(ii) For gas leak detection equipment using EPA Method 21, the verification must be completed as specified in subsection (i).
(iii) For a Department-approved method, a copy of the request for approval that shows the method’s equivalence to subsection (h) or subsection (i).
(7) A sitemap.
(8) If using OGI, a defined observation path that meets the following:
(i) Ensures that all fugitive emissions components are within sight of the path.
(ii) Accounts for interferences.
(9) If using EPA Method 21, a list of the fugitive emissions components to be monitored and an identification method to locate them in the field.
(10) A written plan for each fugitive emissions component designated as difficult-to-monitor or unsafe-to-monitor which includes the following:
(i) A method to identify a difficult-to-monitor or unsafe-to-monitor component in the field.
(ii) The reason each component was identified as difficult-to-monitor or unsafe-to-monitor.
(iii) The monitoring schedule for each component identified as difficult-to-monitor or unsafe-to-monitor. The monitoring schedule for difficult-to-monitor components must include at least one survey per year no more than 13 months apart.
(h) Verification procedures for OGI equipment. An owner or operator that identifies OGI equipment in the fugitive emissions monitoring plan in subsection (g)(6)(i) shall complete the verification by doing the following:
(1) Demonstrating that the OGI equipment is capable of imaging a gas:
(i) In the spectral range for the compound of highest concentration in the potential fugitive emissions.
(ii) That is half methane, half propane at a concentration of 10,000 ppm at a flow rate of less than or equal to 60 grams per hour (2.115 ounces per hour) from a 1/4-inch diameter orifice.
(2) Performing a verification check each day prior to use.
(3) Determining the equipment operator’s maximum viewing distance from the fugitive emissions component and how the equipment operator will ensure that this distance is maintained.
(4) Determining the maximum wind speed during which monitoring can be performed and how the equipment operator will ensure monitoring occurs only at wind speeds below this threshold.
(5) Conducting the survey by using the following procedures:
(i) Ensuring an adequate thermal background is present to view potential fugitive emissions.
(ii) Dealing with adverse monitoring conditions, such as wind.
(iii) Dealing with interferences, such as steam.
(6) Following the manufacturer’s recommended calibration and maintenance procedures.
(i) Verification procedures for gas leak detection equipment using EPA Method 21. An owner or operator that identifies gas leak detection equipment using EPA Method 21 in the fugitive emissions monitoring plan in subsection (g)(6)(ii) shall complete the verification by doing the following:
(1) Verifying that the gas leak detection equipment meets:
(i) The requirements of Section 6.0 of EPA Method 21 with a fugitive emissions definition of 500 ppm or greater calibrated as methane using an FID-based instrument.
(ii) A site-specific fugitive emission definition that would be equivalent to subparagraph (i) for other equipment approved for use in EPA Method 21 by the Department.
(2) Using the average composition of the fluid, not the individual organic compounds in the stream, when performing the instrument response factor of Section 8.1.1 of EPA Method 21.
(3) Calculating the average stream response factor on an inert-free basis for process streams that contain nitrogen, air or other inert gases that are not organic hazardous air pollutants or VOCs.
(4) Calibrating the gas leak detection instrument in accordance with Section 10.1 of EPA Method 21 on each day of its use using zero air, defined as a calibration gas with less than 10 ppm by volume of hydrocarbon in air, and a mixture of methane in air at a concentration less than 10,000 ppm by volume as the calibration gases.
(5) Conducting the surveys which, at a minimum, must comply with the relevant sections of EPA Method 21, including Section 8.3.1.
(j) Fugitive emissions detection devices. Fugitive emissions detection devices must be operated and maintained in accordance with manufacturer-recommended procedures and as required by the test method or a Department-approved method.
(k) Background adjustment. For LDAR inspections using a gas leak detector in accordance with EPA Method 21, the owner or operator may choose to adjust the gas leak detection instrument readings to account for the background organic concentration level as determined by the procedures of Section 8.3.2 of EPA Method 21.
(l) Repair and resurvey provisions. The owner or operator shall repair a leak detected from a fugitive emissions component as follows:
(1) A first attempt at repair must be made within 5 calendar days of detection, and repair must be completed no later than 15 calendar days after the leak is detected unless:
(i) The purchase of a part is required. The repair must be completed no later than 10 calendar days after the receipt of the purchased part.
(ii) The repair is technically infeasible because of one of the following reasons:
(A) It requires vent blowdown.
(B) It requires facility shutdown.
(C) It requires a well shut-in.
(D) It is unsafe to repair during operation of the unit.
(iii) A repair that is technically infeasible under subparagraph (ii) must be completed at the earliest of the following:
(A) After a planned vent blowdown.
(B) The next facility shutdown.
(C) Within 2 years.
(2) The owner or operator shall resurvey the fugitive emissions component no later than 30 calendar days after the leak is repaired.
(3) For a repair that cannot be made during the monitoring survey when the leak is initially found, the owner or operator shall do one of the following:
(i) Take a digital photograph of the fugitive emissions component which includes:
(A) The date the photo was taken.
(B) Clear identification of the component by location, such as by latitude and longitude or other descriptive landmarks visible in the picture.
(ii) Tag the component for identification purposes.
(4) A gas leak is considered repaired if:
(i) There is no visible leak image when using OGI equipment calibrated according to subsection (h).
(ii) A leak concentration of less than 500 ppm as methane is detected when the gas leak detector probe inlet is placed at the surface of the fugitive emissions component for a gas leak detector calibrated according to subsection (i).
(iii) There are no detectable emissions consistent with Section 8.3.2 of EPA Method 21.
(iv) There is no bubbling at the leak interface using the soap solution bubble test specified in Section 8.3.3 of EPA Method 21.
(m) Recordkeeping and reporting requirements. The owner or operator of a fugitive emissions component subject to this section shall maintain the records under § 129.140(g) and submit the reports under § 129.140(k)(3)(vi).
Authority The provisions of this § 129.137 added under section 5(a)(1) and (8) of the Air Pollution Act (35 P.S. § 4005(a)(1) and (8)).
Source The provisions of this § 129.137 added December 9, 2022, effective December 2, 2022, 52 Pa.B. 7635.
Cross References This section cited in 25 Pa. Code § 129.131 (relating to general provisions and applicability); 25 Pa. Code § 129.132 (relating to definitions, acronyms and EPA methods); 25 Pa. Code § 129.138 (relating to covers and closed vent systems); and 25 Pa. Code § 129.140 (relating to recordkeeping and reporting).
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