team anywhere else. Emission factors are developed using year specific GHGRP data. The 2021 IPCC Report notes that anthropogenic methane emissions account for approximately one-third of warming of global average surface temperatures attributed to well-mixed GHG[10] (Feb. 2022) (Compendium). These State programs conduct regular inspections and enforce State safety regulations over intrastate distribution pipelines. However, facilities storing or carrying natural gas or LNG are typically subject to the standards for gas production and transmission systems in 40 CFR part 60. Type B and Type C Gathering Pipelines192.9, J. Miscellaneous Changes in Parts 191 and 192 To Reflect Codification in Federal Regulation of the Congressional Mandate To Address Environmental Hazards of Leak From Gas Pipelines, 191.11Distribution System: Annual Report, 191.17Transmission Systems; Gathering Systems; Liquefied Natural Gas Facilities; and Underground Natural Gas Storage Facilities; Annual Report, 191.19Large-Volume Gas Release Reports, 191.23Reporting Safety-Related Conditions, 191.29National Pipeline Mapping System. 260. The 2020 study by Weller et.al. harm among the hazards addressed in certain part 191 and 192 requirements, consistent with section 118 of the PIPES Act of 2020. Details Phone: (251) 639-4567 Address: 7442 Johnson Ct, Mobile, AL 36695 Website: http://americanleakdetection.com Pertinent requirements vary from one State to the next and even within a single State based on the type (gathering, transmission, or distribution) of pipeline in question or the gas being transported. PHMSA seeks comment on which portions of this proposed rule should or should not be severable. PHMSA proposes to allow an extension of the repair deadline requirements for individual grade 3 leaks only on a case-by-case basis. PHMSA proposes an exception from 191.23 safety-related condition reporting requirements for events that are reported as large-volume gas releases. EPA's notice of proposed rulemaking titled Accidental Release Prevention Requirements: Risk Management Programs Under the Clean Air Act; Safer Communities by Chemical Accident Prevention, 87 FR 53556 (Aug. 31, 2022) (proposing to require, under the Clean Air Act Risk Management Program, that industrial chemical facilities evaluate ways to address natural disasters and consider steps to prevent releases that may result, even before such events occur). Finally, an UNGSF is defined at 192.3 as a gas pipeline facility that stores natural gas underground incidental to the transportation of natural gas, including: (1) a depleted hydrocarbon reservoir; (2) an aquifer reservoir; or (3) a solution-mined salt cavern. Leak detection equipment must be capable of detecting and locating all methane leaks producing a reading of 5 parts per million or more of within 5 feet of the component or equipment surveyed. However, PHMSA proposes to require operators to prioritize repair of some grade 2 leaks based on their higher potential for public safety and environmental consequences. www.dot.gov/privacy. While any leak of methane from a gas pipeline system necessarily entails environmental harm proportional to the amount of methane released to the atmosphere, PHMSA proposes introducing minimum sensitivity standards for leak detection equipment at 192.763 (discussed below) in recognition that some leaks are so small that the harm they present does not warrant expending the resources necessary to detect and repair them, particularly where the leak is approaching the limits of detection with commercially available advanced technologies. PHMSA proposes to define a Consistent with section 113 of the PIPES Act of 2020, PHMSA proposes to require the use of leak detection equipment and practices meeting the ALDP standard in proposed 192.763 (see section IV.B) for leakage surveys on most onshore gas transmission and Types A, B and C gathering pipelines. PHMSA does not propose to require mitigation for emergency blowdowns pursuant to an emergency plan under 192.615(a)(3) or 193.2509 so as to ensure that emissions mitigation will not come at the expense of public safety and other environmental resources; however, PHMSA proposes at 192.770(b) and 193.2523(b) to require that operators document such events, including the justification for not taking mitigative action.[276]. 12024932251. This proposal requires an operator to choose from among prescribed, proven, cost-effective mitigation measures when performing blowdowns related to operations, maintenance, or construction. at 1115, 1135 & Figure 25.4 (2018). We are THE original leak detection specialists. Grade 1 leaks. 98. Earlier, the 2017 Atlantic hurricane season produced the second and third costliest hurricanes in U.S. history, hurricane Harvey and Hurricane Maria. (7) Any leak that can be seen, heard, or felt, and which is in a location that may endanger the general public or property. (i) et. 17. In this situation, remediation of a repair of a grade 3 leak would be completed before the initial repair deadline of 24 months from the date of initial detection. PHMSA proposes to clarify what is considered property damage for the purpose of determining whether a release is reportable as an incident pursuant to 191.9 or 191.15. PHMSA's references to part 192 within this NPRMincluding the proposed amended regulatory text at its conclusionreflect the regulatory text and organization as amended by the RIN2 Final Rule unless otherwise noted. PHMSA therefore expects that more frequent patrols and leakage surveys and prompt remediation would result in earlier detection and potential avoidance of leak degradation that would lead to incidents. PHMSA expects this NPRM would impose compliance costs of $100 million or more (in 1996 dollars) on private sector entities. Start Printed Page 31977. (noting that an LNG terminal had reported several natural gas releases to the state Department of Environmental Quality, including one release of 180,000 pounds of methane in January 2022). Pgs. At the May 2021 Public Meeting, Siemens Energy and ProFlex Technologies presented on a negative pressure wave sensing technology for detecting spontaneous leaks on gas transmission, gas gathering, and similar applications. PHMSA estimates that it may receive 1,000 requests on average per year from gas distribution operators to extend the deadline for remedying leaks, with each of these requests requiring approximately 8 hours to prepare. 247. A handful of states specify allowable leak detection equipment, generally requiring the use of an FID or equivalent device. American Leak Detection in Mobile, AL 36695 - AL.com [252] Action to stop the flow of gas should be defined in an operator's abnormal operating procedures and could include reconfiguring the relief device. PHMSA proposes to revise 192.706 to increase the minimum frequency for performing leakage surveys of gas transmission, offshore gas gathering, and Types A, B, and C gathering pipelines, each located in HCAs in Class 1, Class 2, and Class 3 locations, to twice each calendar year at intervals not exceeding 7 Advanced Leak Detection Performance Standard192.763(b), 6. European Parliament, EU BriefingFit for 55 Package: Reducing Methane Emissions in the Energy Sector (Mar. (c) An operator must investigate a known leak, including conducting a leakage survey for possible gas migration, as soon as practicable when freezing ground, heavy rain, flooding, or other changes to the environment occur that could affect the venting of gas or could cause migration of gas to the outside wall of a building. 280. As explained in section II.C above, fugitive methane emissions from natural gas compressor stations on gas transmission and gas gathering pipelines comprise a significant share of fugitive emissions from those facilities. The methodology of multiplying an activity factor (such as pipeline mileage) by an emissions factor to extrapolate an estimate of overall emissions for a given source is considered a bottom-up approach that can be contrasted with a top-down approach taking total emissions measured at larger ( Section 192.1007 requires operators to demonstrate an understanding of their gas distribution systems based on reasonably available information. See Pipelines known to leak based on their material (including, but not limited to, cast iron, unprotected steel, wrought iron, and historic plastics with known issues), design, or past operating and maintenance history; and. White House Office of Domestic Climate Policy, For this reason, continuous monitoring can be especially effective at aboveground facilities where probable fugitive emissions sources are known In the Preliminary RIA, PHMSA considers an alternative where the 5- https://www.ingaa.org/News/PressReleases/38353.aspx Start Printed Page 31951 [272] For a leak that is upgraded, the repair deadline is the earlier of the remaining repair deadline for the original grade, or the repair deadline under the new leak grade measured from the date the operator receives the information that a higher-priority grade condition exists. 49, no. Further, if a previously detected leak later results in an incident causing significant safety and environmental consequences, then it almost certainly would have been an existing or probable hazard to persons and the environment at the time of detection and should have been graded and repaired accordingly. PHMSA therefore proposes to address these regulatory gaps by establishing requirements at 192.703, 192.760, and 192.769 for all part 192-regulated gas pipeline operators to ensure properly-trained personnel grade and repair all leaks pursuant to a schedule for each grade based on the severity of public safety and environmental risks. This mandatory information collection covers the collection of data from operators of natural gas pipelines, UNGSFs, and LNG facilities for annual reports. The requested revision would reduce the burden for this information collection by 3 responses and 18 burden hours annually. [85] (ix) Any leak that, in the judgment of operating personnel at the scene, is of sufficient magnitude to justify scheduled repair within six months or less. [300] 271. [274] vol. documents in the last year, 39 Call (866) 701-5306 today. (a) Each operator of an LNG facility, including mobile, temporary, and satellite facilities must conduct periodic methane leakage surveys, on equipment and components within their facilities containing methane or LNG, at least four times each calendar year, with a maximum interval between surveys not exceeding 4 [237] Toward that end, E.O. [35] NTSB recommended that the International Code Council, the National Fire Protection Association, and the Gas Technology Institute (GTI) cooperate to develop standards and incorporate provisions in applicable national codes to require methane detection systems for all types of residential occupancies with gas service. See PHMSA expects that the proposed regulatory amendments would yield prompt and meaningful reduction of methane emissions, a key contributor to climate change; improve public safety; and mitigate the disproportionate burden of those environmental and safety risks historically placed on minority, low-income, or other underserved and disadvantaged populations and communities. Alternatively, a pressure relief may malfunction by operating before those criteria have been satisfied, which results in unnecessary releases of gas to the atmosphere. Aside from the public safety risks discussed above, leaks from gas distribution, transmission, and gathering pipelines are also a significant contributor to climate change. 21370635. that reasonably prudent operators would maintain in ordinary course to protect public safety and the environment from the pressurized (natural flammable, corrosive, or toxic) gases transported in their pipelines. Displaying 1 - 13 of 13. PHMSA proposes to characterize a grade 1 leak as an existing or probable hazard to persons and property or grave hazard to the environment. that agencies use to create their documents. PI93009 (February 11, 1993) (recommending public stakeholder consult the GPTC Guide for further determination of instruments and techniques to be used in certain leak detection activities); See74 FR 31675, 31677 (July 2, 2009). also suggested that applying prescriptive regulations could potentially limit the development of different technologies and innovations, stating that providing operators with flexibility can create opportunities and incentives for developing new technologies and innovations in leak detection and measurement. Only a handful of States have imposed their own, more demanding leak repair requirements than PHMSA's. The first element in an ALDP is the leak detection equipment that operators would use to perform leakage surveys, pinpoint leak locations, and investigate leaks. And distribution pipelines outside of business districts at a high risk of leakage would generally be obliged to conduct leakage surveys more frequently: once each calendar year, with the interval between surveys not to exceed 15 months. Would recommend to my friends in the future, water is too expensive to let a leak go on ! These include, vaults, certain tunnels, catch basins, and manholes. NFPA, The LEL of natural gas is 5% gas by volume. Records validating equipment performance must be maintained for five years after the For other provisions (specifically, 192.605(b)(9), 192.613(b), 192.615(a), 192.615(a) introduction, 192.616(d)(2) and (j)(2), and 192.703(c)), existing language referring to hazard and hazardous leak is elastic enough to accommodate PHMSA's proposed expansion of the hazard concept to encompass environmental hazards without revision of regulatory text. Vol. The RSPA incident report form in 1991 similarly did not require operators to provide an estimate of release volume. [127] Start Printed Page 31958 See reviews, photos, directions, phone numbers and more for American Leak locations in Mobile, AL. Audio, Transcripts, and Presentations at For example, PHMSA proposes to require any leak on a gas transmission or Type A gathering pipeline, each in an HCA or a Class 3 or Class 4 location (and that is not a grade 1 leak) to be repaired within 30 days of detection, or the operator must take continuous action to monitor and repair the leak. 21 (May 2022), These techniques can ensure that a leak is not an immediate hazard to persons or property and justify downgrading the leak to a grade 2 leak. (iii) A reading of less than 20% of the LEL in a confined space. Further, leaks are a more frequent cause of incidents on Types A and B gas gathering pipelines than for gas transmission pipelinesoperators attributed nearly 80% of the incidents reported on Types A and B gathering pipelines to leaks. e.g., (last accessed June 20, 2022). In particular, leak rate measurements may help operators quickly grade certain leaks as grade 2 leaks based on a leak rate in excess of 10 CFH. [140] Specifically, PHMSA proposes to require that an ALDP must be capable of detecting all leaks that produce a reading of 5 ppm or greater of gas when measured from a distance of 5 feet from the pipeline, or within a wall-to-wall paved area. 1,446. Therefore, the total number of leaks on Types A and B gathering lines not subject to any meaningful Federal repair requirements is likely even higher. 97. Lastly, section 118 of the PIPES Act of 2020 amended the criteria set forth at 49 U.S.C. OMB Control Number: PHMSA proposes to limit the extensions to grade 3 leaks, which inherently pose lower risks to public safety and the environment than grades 1 and 2 leaks. 58 FR 51735 (Oct. 4, 1993). Note that a blowdown that is not mitigated may also be reportable under the proposed large-volume gas release report. Comments on each of these questions are especially helpful when they are supported by research or operational experience, along with the potential safety and environmental benefits and potential costs of a particular approach (including whether that approach would be technically feasible, cost-effective, and practicable).