{"operation":"document","citation":"CPF 42023007CAO","title":"ENABLE GAS TRANSMISSION, LLC — Corrective Action Order","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"current","official":true,"published_on":"2023-10-13","effective_on":null,"summary":"OPEN corrective action order.","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-42023007cao.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-42023007cao.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-42023007cao","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/42023007CAO","body":"Corrective Action Order involving ENABLE GAS TRANSMISSION, LLC. The dataset does not identify a cited regulation for this case. The case was opened on 2023-10-13 and is reported as open. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n42023007CAO_Corrective Action Order (Amended)_10312023_(23-288850).pdf: https://primis.phmsa.dot.gov/enforcement-documents/42023007CAO/42023007CAO_Corrective%20Action%20Order%20(Amended)_10312023_(23-288850).pdf\n\n42023007CAO_Corrective Action Order (Amended)_10312023_(23-288850)_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/42023007CAO/42023007CAO_Corrective%20Action%20Order%20(Amended)_10312023_(23-288850)_text.pdf\n\n42023007CAO_Corrective Action Order_10132023_(23-288850).pdf: https://primis.phmsa.dot.gov/enforcement-documents/42023007CAO/42023007CAO_Corrective%20Action%20Order_10132023_(23-288850).pdf\n\n42023007CAO_Corrective Action Order_10132023_(23-288850)_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/42023007CAO/42023007CAO_Corrective%20Action%20Order_10132023_(23-288850)_text.pdf\n\n42023007CAO_Operator RFH and SOI_10232023_(23-288850).pdf: https://primis.phmsa.dot.gov/enforcement-documents/42023007CAO/42023007CAO_Operator%20RFH%20and%20SOI_10232023_(23-288850).pdf\n\n42023007CAO_Operator Withdrawal of Hearing Request_11132023_(23-288850).pdf: https://primis.phmsa.dot.gov/enforcement-documents/42023007CAO/42023007CAO_Operator%20Withdrawal%20of%20Hearing%20Request_11132023_(23-288850).pdf\n\n42023007CAO_Corrective Action Order_10132023_(23-288850)_text.pdf\n\nOctober 13, 2023\nVIA ELECTRONIC MAIL TO: tom.long@energytransfer.com\nThomas Long\nChief Executive Officer\nEnergy Transfer, LP\n8111 Westchester Drive\nDallas, Texas 75225\nCPF No. 4-2023-007-CAO\nDear Mr. Long:\nEnclosed please find a Corrective Action Order (CAO or Order) issued by the Pipeline and\nHazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), in the\nabove-referenced case. It requires Enable Gas Transmission, LLC, a subsidiary of Energy\nTransfer, LP, to take certain corrective actions with respect to a pipeline rupture that occurred on\nOctober 4, 2023, on its 24-inch natural gas transmission pipeline near Jessieville, Arkansas.\nService of the CAO by electronic transmission is deemed complete upon transmission and\nacknowledgement of receipt, or as otherwise provided under 49 C.F.R. § 190.5. The terms and\nconditions of this Order are effective upon completion of service.\nThank you for your cooperation in this matter.\nSincerely,\nAlan K. Mayberry\nAssociate Administrator\nfor Pipeline Safety\nEnclosure: CAO\ncc: Linda Daugherty, Deputy Associate Administrator for Field Operations, Office of\nPipeline Safety, PHMSA\nBryan Lethcoe, Director, Southwest Region, Office of Pipeline Safety, PHMSA\n\n\n\nGreg McIlwain, Executive Vice President of Operations, Energy Transfer, LP,\ngregory.mcilwain@energytransfer.com\nEric Amundsen, Senior Vice President of Operations, Energy Transfer, LP,\neric.amundsen@energytransfer.com\nTodd Stamm, Senior Vice President of Operations, Energy Transfer, LP,\ntodd.stamm@energytransfer.com\nJennifer Street, Senior Vice President of Operations Services, Energy Transfer, LP,\njennifer.street@energytransfer.com\nHeidi Murchison, Chief Counsel, Energy Transfer, LP,\nheidi.murchison@energytransfer.com\nLeif Jensen, Vice President of Tech Services, Energy Transfer, LP,\nleif.jensen@energytransfer.com\nTodd Nardozzi, Director, Regulatory Compliance, Energy Transfer, LP,\ntodd.nardozzi@energytransfer.com\nSusie Sjulin, Director, Regulatory Compliance, Energy Transfer, LP,\nsusie.sjulin@energytransfer.com\nCONFIRMATION OF RECEIPT REQUESTED\n\n\n\nU.S. DEPARTMENT OF TRANSPORTATION\nPIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION\nOFFICE OF PIPELINE SAFETY\nWASHINGTON, D.C. 20590\n____________________________________\nIn the Matter of )\nEnable Gas Transmission, LLC, a ) CPF No. 4-2023-007-CAO\nsubsidiary of Energy Transfer, LP, )\n)\n)\n)\nRespondent. )\n____________________________________)\nCORRECTIVE ACTION ORDER\nPurpose and Background\nThis Corrective Action Order (CAO or Order) is being issued by the Pipeline and Hazardous\nMaterials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), under the authority\nof 49 U.S.C. § 60112 and 49 C.F.R. § 190.233, to require Enable Gas Transmission, LLC (Enable),\na subsidiary of Energy Transfer, LP (together “Respondent”), to take the necessary corrective\nactions to protect the public, property, and the environment from potential hazards associated with\nthe October 4, 2023, failure of its 24-inch natural gas transmission pipeline in Jessieville, Arkansas\n(Incident). The Incident occurred near Arkansas Highway 298, in a rural area with few buildings.\nRespondent’s Malvern AR-7 Pipeline System at the Jessieville Junction Station in Garland County,\nArkansas, includes the following pipelines that share a common right-of-way: BT-1-AN (24-inch),\nBT-1 (30-inch), BT-1 (16-inch), and BT-1-AS (16-inch) pipeline. Respondent’s BT-1-AN 24-\ninch pipeline runs approximately 40 miles between the Dunn Compressor Station and Jessieville\nJunction Station.\nAt approximately 4:43 p.m. CDT, Respondent’s control room personnel received a call from a\nmember of the public reporting a loud noise and fire in the vicinity of the failure. Respondent’s\ncontrol room personnel reviewed BT-1-AN’s operating indications and noted pressure dropping\nwith flow increasing. At approximately 4:45 p.m. and 4:47 p.m. CDT, the control room personnel\nnotified Russellville and Malvern pipeline technicians, respectively, of the indication of pressure\nloss and the information relayed by the public. At approximately 4:48 p.m. CDT, control room\npersonnel received a rate-of-change alarm for the BT-1-AN pipeline, indicating a rapid loss of line\npressure. At approximately 4:49 p.m. CDT, pipeline technicians notified the Malvern OPS\nsupervisor of a possible pipeline failure near Jessieville, Arkansas. At approximately 4:53 p.m.\nCDT, pipeline technicians were dispatched to the reported failure site, and to pipeline isolation\nvalves upstream and downstream of the reported failure location. At approximately 5:29 p.m.\nCDT, a pipeline technician arrived at the failure site in Jessieville, Arkansas, and confirmed a\n\n\n\npipeline failure. At approximately 5:31 p.m. CDT, the downstream isolation valve (Gate 88 Valve)\nwas manually shut approximately 12 miles south of the failure site. At approximately 6:15 p.m.\nCDT, Respondent determined that the following pipeline segments were impacted: BT-1-AN (24-\ninch), BT-1 (16-inch), BT-1-AS (16-inch), and BT-1 (30-inch). At approximately 6:30 p.m. CDT,\nthe upstream isolation valve (Dry Fork Valve) was manually shut approximately 13 miles north of\nthe failure site, which isolated BT-1 and BT-1-AN. The failure location was determined to be\nRespondent’s BT-1-AN 24-inch natural gas transmission pipeline at approximately mile post (MP)\n3830+51 to 3831+28 (Jessieville Junction Station) in Jessieville, Arkansas. The failure resulted\nin the ejection of at least two portions of pipe: approximately 34 feet of pipe, which landed on the\nyard fence towards the northeast approximately 55 feet from the failure location, and\napproximately 9 feet of pipe, which landed on the other side of the dirt road towards the east\napproximately 180 feet from the failure location. Other pipeline equipment located at the failure\nsite, including a launching station and associated equipment, was damaged or destroyed. The\nrupture ignited and resulted in a large fire at the rupture site and smaller fires in the surrounding\nforest, along the road, and adjacent property. A nearby deer blind and pine trees along the right-\nof-way were destroyed. Two occupants of a home approximately one mile from the failure site\nwere temporarily evacuated from the residence.\nPursuant to 49 U.S.C. § 60117, PHMSA, OPS, initiated an onsite investigation of the Incident.\nThe preliminary findings of PHMSA’s ongoing investigation are outlined below.\nPreliminary Findings\n• On October 4, 2023, at approximately 4:43 p.m. CDT, Respondent received a call\nfrom a member of the public reporting a loud noise and fire in the vicinity of the\nfailure. At approximately 4:44 p.m. CDT, Respondent’s control room personnel\nobserved a dropping pressure and increasing flow on the SCADA screen, indicating a\npossible failure of Respondent’s pipeline. At approximately 4:45 p.m. and 4:47 p.m.\nCDT, the control room personnel notified Russellville and Malvern Team pipeline\ntechnicians, respectively, of a possible pipeline failure. At approximately 4:48 p.m.\nCDT, the control room personnel received a rate-of-change alarm indicating a rapid\nloss of line pressure.\n• At approximately 4:49 p.m. CDT, the Malvern Team pipeline technician notified the\nOperations Supervisor (OPS supervisor) of a possible pipeline failure with a fire near\nJessieville, Arkansas. At approximately 4:50 p.m. CDT, control room personnel\nnotified the Gas Control Manager of the potential failure and requested support. At\napproximately 4:53 p.m. CDT, the OPS supervisor notified the Senior Director of\nOperations of a potential failure on the BT pipeline system, and Malvern pipeline\ntechnicians were dispatched to the failure site near Jessieville, Arkansas, and Dry\nFork Valve and Gate 88 Valve upstream and downstream of the failure site,\nrespectively.\n• At 5:04 p.m. CDT, the Gas Control Manager notified the Senior Director of Gas\nControl and System Planning of the potential failure. At approximately 5:13 p.m.\nCDT, the Gas Control Manager notified the Lead Mechanic of the Dunn Team and\n\n\n\nrequested on-site support at the Dunn Compressor Station. At approximately 5:19\np.m. CDT, the Senior Director of Operations set up a Teams conference bridge with\nstakeholders to assist in facilitating the isolation and control of the potential failure.\n• At approximately 5:29 p.m. CDT, the pipeline technician arrived at the failure site\nand confirmed a pipeline failure with a fire at Jessieville Junction. At approximately\n5:31 p.m. CDT, a Malvern pipeline technician isolated the BT-1-AS 16-inch pipeline\nat downstream Gate 88 Valve.\n• At approximately 6:15 p.m. CDT, Respondent determined that the BT-1-AN 24-inch,\nBT-1 16-inch, BT-1-AS 16-inch, and BT-1 30-inch pipelines were impacted by the\nfailure, and the BT-1 16-inch pipeline was isolated at downstream Gate 88 Valve. At\napproximately 6:30 p.m. CDT, a pipeline technician isolated BT-1 and BT-1-AN at\nupstream Dry Fork Valves. At approximately 11:05 p.m. CDT, Respondent’s on-site\npersonnel confirmed that the fire at the failure site had significantly diminished and\nwas under control. Respondent's personnel remained overnight at the location of the\nfailure, Gate 88 Valve, and Dry Fork Valves.\n• At approximately 7:44 a.m. CDT on October 5, 2023, Respondent confirmed that the\nfire at the failure site was extinguished. At approximately 8:00 a.m. CDT,\nRespondent initiated the operation of air movers at both the Dry Fork Valve and Gate\n88 Valve. At approximately 12:55 p.m. CDT, the failure site was cleared for access.\n• Both BT-1-AN 24-inch and BT-1 16-inch pipelines were isolated from approximately\n13 miles upstream (north of failure location) at Dry Fork Valve and 12 miles\ndownstream (south of failure location) at Gate 88 Valve. All pipelines entering and\nleaving the Jessieville Junction Station remain in a shutdown condition.\n• The failure occurred at approximately mile post (MP) 3830+51 to 3831+28 at\nJessieville Junction Station on Respondent’s Malvern AR-7 Pipeline System BT-1-\nAN 24-inch line in Jessieville, Arkansas.\n• Respondent reported the Incident to the National Response Center (NRC) at 5:44 p.m.\nCDT on October 4, 2023 (NRC Report No. 1380909), indicating there was a fire and\nrelease of gas of approximately 99,860 MCF.\n• The natural gas was released to the atmosphere with no injuries or fatalities\nassociated with this incident. Two occupants of a home approximately one mile from\nthe failure location were temporarily evacuated from the residence. The failure\nresulted in an explosion and fire when the gas ignited and caused the ejection of at\nleast two portions of pipe: approximately 34 feet of 24-inch pipe, which landed on the\nyard fence towards the northeast direction approximately 55 feet from the failure\nlocation, and approximately 9 feet of 24-inch pipe, which landed on the other side of\nthe dirt road towards the east direction approximately 180 feet from the failure\nlocation. A third small piece of pipe was discovered approximately 90 feet to the\n\n\n\nsouthwest of the failure site. It is currently unknown whether the third piece was\nejected as a result of the pipeline failure.\n• Launching equipment for the 16-inch BT-1 pipeline was destroyed in the rupture.\n• The maximum allowable operating pressure (MAOP) of BT-1-AN is 1000 pounds per\nsquare inch gauge (psig), which was determined by hydrostatic testing under 49\nC.F.R. § 192.619(a)(2). The operating pressure before the Incident was 960 psig, and\n562 psig immediately after the failure. The maximum operating pressure between\nSeptember 28, 2023, and October 4, 2023, was recorded at 978 psig. The discharge\npressure at the Dunn Compressor Station is set at 780 psig.\n• The MAOP of BT-1 (16-inch) is 1000 pounds per square inch gauge (psig), which\nwas determined by hydrostatic testing under 49 C.F.R. § 192.619(a)(2). The normal\noperating pressure is 960 psig.\n• Respondent shut the downstream Gate 88 Valve, approximately 12 miles south of the\nIncident, at 5:31 p.m. CDT, and shut the upstream Dry Fork Valve, approximately 13\nmiles north of the Incident at 6:30 p.m. CDT. Respondent also shut in the parallel\nline at similar distances.\n• The BT-1-AN pipeline was constructed of 24-inch OD x 0.281-inch w.t., X-60 double\nsubmerged arc welded (DSAW) pipe manufactured by U.S. Steel in 1967. The\ncoating type of the failed BT-1-AN pipeline segment is unknown. The pipeline is\ncathodically protected.\n• The BT-1 pipeline was constructed of 16-inch OD x 0.25-inch w.t., X-46 electric\nresistance welded (ERW) pipe constructed in 1984. The coating type of the 16-inch\nBT-1 pipeline segment is unknown. The pipeline is cathodically protected.\n• Respondent’s BT-1 (16- and 30-inch), BT-1-AN (24-inch), and BT-1-AS (16-inch)\npipelines are gas pipeline facilities subject to the pipeline safety laws in 49 U.S.C.\nchapter 601 and 49 C.F.R. part 192.\n• BT-1-AN is one of two parallel natural gas transmission pipelines in a common right-\nof-way. The two parallel pipelines are comprised of four separately named pipelines\nthat connect at a common manifold at Jessieville Junction Station. BT-1-AN runs\nfrom Dunn Compressor Station to Jessieville Junction Station for approximately 40\nmiles. BT-1 16-inch pipeline runs parallel with BT-1-AN between Dunn Compressor\nStation and Jessieville Junction Station. BT-1-AS runs from Jessieville Junction\nStation to the Gate 88 Valve. BT-1 30-inch pipeline runs parallel with BT-1-AS\nbetween Jessieville Junction Station and Gate 88 Valve.\n• BT-1-AN, BT-1-AS, and BT-1 (16- and 30-inch) traverse mostly Class 1 and 2\nlocations. The Incident occurred in a heavily forested area with potential impacts to\nwildlife.\n\n\n\n• A visual inspection of the failed pipe segment by Respondent’s on-site personnel\nappeared to show an area of extensive external corrosion with one area reading 0.130-\ninches or 46% remaining wall thickness. The rupture and ignition of the pipeline\ncaused extensive damage to nearly all aboveground piping and appurtenances at the\nJessieville Junction Station.\n• Respondent has begun preparation to transport pipe samples from the failed segment\nto a third-party lab for examination. Respondent began excavation of the two ends of\nthe ruptured pipe at approximately 4:00 p.m. CDT on October 6, 2023. On October\n7, 2023, the two known ejected pieces (34-feet, 9-feet), and the small piece that is of\nunknown origin, were loaded onto a truck and shipped to Houston, Texas, for testing.\nThe two ends of the pipe that the ejected piece broke away from will be shipped out\non a later truck.\n• On May 2, 2019, Respondent’s Malvern AR-7 BT-1 30-inch pipeline (5.67 miles\nsouth of the Incident) ruptured due to near-neutral pH stress corrosion cracking in an\narea of external corrosion. On November 24, 2014, Respondent’s Malvern AR-7 BT-\n1-AN 24-inch pipeline (1.25 miles north of the Incident) cracked due to near-neutral\npH stress corrosion cracking.\nDetermination of Necessity for Corrective Action Order and Right to Hearing\nSection 60112 of Title 49, United States Code, authorizes PHMSA to determine that a pipeline\nfacility is or would be hazardous to life, property, or the environment and if there is a likelihood\nof serious harm, to issue an order without prior notice to the operator of the facility to take\nnecessary corrective action, including suspended or restricted use of the facility, physical\ninspection, testing, repair, replacement, or other appropriate action. An order issued without notice\nmust provide an opportunity for a hearing as soon as practicable after the order is issued.\nIn deciding whether to issue an order, PHMSA must consider the following, if relevant: (1) the\ncharacteristics of the pipe and other equipment used in the pipeline facility, including the age,\nmanufacturer, physical properties, and method of manufacturing, constructing, or assembling the\nequipment; (2) the nature of the material the pipeline facility transports, the corrosive and\ndeteriorative qualities of the material, the sequence in which the material are transported, and the\npressure required for transporting the material; (3) the aspects of the area in which the pipeline\nfacility is located, including climatic and geologic conditions and soil characteristics; (4) the\nproximity of the area in which the natural gas pipeline facility is located to environmentally\nsensitive areas; (5) the population density and population and growth patterns of the area in which\nthe pipeline facility is located; (6) any recommendation of the National Transportation Safety\nBoard made under another law; and (7) other factors PHMSA may consider appropriate.\nAfter evaluating the foregoing preliminary findings of fact, and having considered the age of the\npipelines, the material properties of the pipelines, the hazardous nature of the product transported,\nthe proximity of the pipelines to heavily forested areas and a residential home, the pressure\nrequired for transporting the material, the uncertainty as to the cause of the failure, the uncertainty\n\n\n\nof potential impacts of the Incident to the parallel pipeline (BT-1 16-inch), the destruction of\nlaunching equipment associated with BT-1 (16-inch), a prior failure on this pipeline (BT-1-AN)\nin 2014 approximately 1.25 miles north of the Incident location due to near-neutral pH stress\ncorrosion cracking, a more recent failure in 2019 downstream of the Incident (BT-1 30-inch) also\ndue to near-neutral pH stress corrosion cracking, and the possibility that the same condition(s) that\nmay have caused the October 4, 2023, failure remain present in the pipeline that failed and parallel\npipeline (16-inch BT-1 & BT-1-AS), I find that continued operation of the pipeline without\ncorrective measures is or would be hazardous to life, property, or the environment, and that failure\nto issue this Order without notice would result in the likelihood of serious harm.\nAccordingly, under 49 C.F.R. § 190.233(b), this Order mandating immediate corrective action is\nissued without prior notice and opportunity for a hearing. The terms and conditions of this Order\nare effective upon receipt.\nWithin 10 days of receipt of this Order, Respondent may request a hearing, to be held as soon as\npracticable, by notifying the Associate Administrator for Pipeline Safety in writing, with a copy\nto the Director, Southwest Region, PHMSA (Director). If a hearing is requested, it will be held in\naccordance with 49 C.F.R. § 190.211.\nAfter receiving and analyzing additional data in the course of this investigation, PHMSA may\nidentify other corrective measures that need to be taken. Respondent will be notified of any\nadditional measures required and, if appropriate, PHMSA will consider amending this Order. To\nthe extent consistent with safety, Respondent will be afforded notice and an opportunity for a\nhearing prior to the imposition of any additional corrective measures.\nRequired Corrective Actions\nDefinitions:\nAffected Pipelines – The “Affected Pipelines” means Respondent’s 16-inch (BT-1) and 24-\ninch (BT-1-AN) natural gas transmission pipelines upstream of Jessieville Junction Station\n(from Dunn Compressor Station to Jessieville Junction Station) and the 16-inch (BT-1-AS)\nand 30-inch (BT-1) natural gas transmission pipelines downstream of Jessieville Junction\nStation (from Jessieville Junction Station to the Gate 88 Valve).\nIsolated Segments – The “Isolated Segments” means both the 16-inch (BT-1) and the 24-\ninch (BT-1-AN) segments upstream of Jessieville Junction Station (from Dry Fork Valve to\nJessieville Junction Station) and the 16-inch (BT-1-AS) and 30-inch (BT-1) downstream of\nthe Jessieville Junction Station (from Jessieville Junction Station to the Gate 88 Valve).\nDirector – The Director, Southwest Region, Office of Pipeline Safety, PHMSA, 8701 S.\nGessner, Suite 630 Houston Texas 77074.\nPursuant to 49 U.S.C. § 60112, I hereby order Respondent to immediately take the following\ncorrective actions:\n\n\n\n1. 2. 3. Shutdown of the Isolated Segments. The Isolated Segments are currently out of service.\nThe Isolated Segments must remain shut-in and may not be operated until authorized to be\nrestarted by the Director in accordance with the terms of this Order.\nOperating Pressure Restriction. Respondent must reduce and maintain a twenty percent\n(20%) pressure reduction in the actual operating pressure along the entire length of the\nAffected Pipelines such that the operating pressure along the Affected Pipelines will not\nexceed eighty percent (80%) of the actual operating pressure in effect along the Affected\nPipelines immediately prior to the Incident.\na. This pressure restriction is to remain in effect until written approval to increase the\npressure or return the pipeline to its pre-failure operating pressure is obtained from the\nDirector. This written approval may be obtained on an individual pipeline basis within\nthe Affected Pipelines.\nb. Within 15 days of receipt of this Order, Respondent must provide the Director the\nactual operating pressures of each compressor station and each main line pressure\nregulating station on the Affected Pipelines at the time of failure and the reduced\npressure restriction set-points at these same locations.\nc. This pressure restriction requires any relevant remote or local alarm limits, software\nprogramming set-points or control points, and mechanical over-pressure devices to be\nadjusted accordingly.\nd. When determining the pressure restriction set-points, Respondent must take into\naccount any in-line inspection (ILI) features or anomalies present in the Affected\nPipelines to provide for continued safe operation while further corrective actions are\ncompleted.\ne. Respondent must review the pressure restriction monthly by analyzing the operating\npressure data, taking into account any ILI features or anomalies present in the Affected\nPipelines. Respondent must immediately reduce the operating pressure further to\nmaintain the safe operations of the Affected Pipelines, if warranted by the monthly\nreview. Further, Respondent must submit the results of the monthly review to the\nDirector including, at a minimum, the current discharge set-points (including any\nadditional pressure reductions), and any pressure exceedance at discharge set-points.\nSubmittals must be made quarterly, in accordance with Item 14 below.\nRestart Plan. Prior to resuming operation of the Isolated Segments, develop and submit a\nwritten Restart Plan to the Director for prior approval.\na. b. The Director may approve the Restart Plan incrementally without approving the\nentire plan, but the Isolated Segments cannot resume operation until the Restart Plan\nis approved in its entirety.\nOnce approved by the Director, the Restart Plan will be incorporated by reference\ninto this Order.\nc. The Restart Plan must provide for adequate patrolling of the Isolated Segments\nduring the restart process and must include incremental pressure increases during start\nup, with each increment to be held for at least two hours.\n\n\n\nd. The Restart Plan must include sufficient surveillance of the pipeline during each\npressure increment to ensure that no leaks are present when operation of the line\nresumes.\n4. e. The Restart Plan must specify a day-light restart and include advance\ncommunications with local emergency response officials.\nf. The Restart Plan must provide for a review of the Isolated Segments for conditions\nsimilar to those of the failure including a review of construction, operating and\nmaintenance (O&M) and integrity management records such as ILI results,\nhydrostatic tests, root cause failure analysis of prior failures, aerial and ground\npatrols, corrosion, cathodic protection, excavations, and pipe replacements.\nRespondent must address any findings that require remedial measures to be\nimplemented prior to restart.\ng. The Restart Plan must also include documentation of the completion of all mandated\nactions, and a management of change plan to ensure that all procedural modifications\nare incorporated into Respondent’s O&M procedures manual.\nh. The Restart Plan must provide for hydrostatic pressure testing of the Isolated\nSegments.\nReturn to Service. After the Director approves the Restart Plan, Respondent may return\nthe Isolated Segments to service but the operating pressure must not exceed the pressure\nrestrictions in accordance with Item 2 above.\n5. Removal of Pressure Restriction.\n6. a. The Director may allow the removal or modification of the pressure restriction upon a\nwritten request from Respondent demonstrating that restoring the pipeline to its pre-\nfailure operating pressure is justified based on a reliable engineering analysis showing\nthat the pressure increase is safe considering all known defects, anomalies, and\noperating parameters of the pipeline.\nb. The Director may allow the temporary removal or modification of the pressure\nrestrictions upon a written request from Respondent demonstrating that temporary\nmitigative and preventive measures are implemented prior to and during the\ntemporary removal or modification of the pressure restriction. The Director's\ndetermination will be based on available information, including the failure cause and\nprovision of evidence that preventative and mitigative actions taken by the operator\nprovide for the safe operation of the Affected Pipelines during the temporary removal\nor modification of the pressure restriction. Appeals to determinations of the Director\nin this regard will be decided by the Associate Administrator for Pipeline Safety.\nMechanical and Metallurgical Testing. Within 45 days of receipt of this Order,\nRespondent must complete mechanical and metallurgical testing and failure analysis of the\nfailed pipe, including an analysis of soil samples and any foreign materials. Mechanical\nand metallurgical testing must be conducted by an independent third-party approved by the\nDirector, and must document the decision-making process and all factors contributing to\nthe failure. Respondent must complete the testing and analysis as follows:\n\n\n\na. Document the chain-of-custody when handling and transporting the failed pipe\nsection and other evidence from the failure site.\n7. b. Within 10 days of receipt of this Order, develop and submit the testing protocol and\nthe proposed testing laboratory to the Director for prior approval.\nc. Prior to beginning the mechanical and metallurgical testing, provide the Director with\nthe scheduled date, time, and location of the testing to allow for an OPS\nrepresentative to witness the testing.\nd. Ensure the testing laboratory distributes all reports whether draft or final in their\nentirety to the Director at the same time they are made available to Respondent.\nRoot Cause Failure Analysis. Within 90 days following receipt of this Order, complete a\nroot cause failure analysis (RCFA) and submit a final report of this RCFA to the Director.\nThe RCFA must be supplemented or facilitated by an independent third-party approved by\nthe Director and must document the decision-making process and all factors contributing to\nthe failure. The final report must include findings and any lessons learned and whether the\nfindings and lessons learned are applicable to other locations within Respondent’s pipeline\nsystem.\n8. Remedial Work Plan (RWP).\na. b. c. Within 90 days following receipt of this Order, Respondent must submit a remedial\nwork plan (RWP) to the Director for approval.\nThe Director may approve the RWP incrementally without approving the entire RWP.\nOnce approved by the Director, the RWP will be incorporated by reference into this\nOrder.\nd. e. The RWP must specify the tests, inspections, assessments, evaluations, and remedial\nmeasures Respondent will use to verify the integrity of the Affected Pipelines. It must\naddress all known or suspected factors and causes of the Incident. Respondent must\nconsider the risks and consequences of another failure to develop a prioritized\nschedule for RWP-related work along the Affected Pipelines.\nThe RWP must include a procedure or process to:\ni. Identify pipe in the Affected Pipelines with characteristics similar to the\ncontributing factors identified for the Incident, including the age and\nmanufacturer of the entire length of the Affected Pipelines.\nii. Gather all data necessary to review the failure history (in service and pressure test\nfailures) of the Affected Pipelines and to prepare a written report containing all the\navailable information such as the locations, dates, and causes of leaks and\nfailures.\niii. Integrate the results of the metallurgical testing, root cause failure analysis, and\nother corrective actions required by this Order with all relevant pre-existing\noperational and assessment data for the Affected Pipelines. Pre-existing\noperational data includes, but is not limited to, design, construction, operations,\nmaintenance, testing, repairs, prior metallurgical analyses, and any third-party\n\n\n\niv. v. f. consultation information. Pre-existing assessment data includes, but is not limited\nto, ILI tool runs, hydrostatic pressure testing, direct assessments, close interval\nsurveys, and DCVG/ACVG surveys.\nDetermine if conditions similar to those contributing to the Incident are likely to\nexist elsewhere on the Affected Pipelines.\nConduct additional field tests, inspections, assessments, and evaluations to\ndetermine whether, and to what extent, the conditions associated with the Incident\nand other failures from the failure history (see (e)(ii) above) or any other integrity\nthreats are present elsewhere on the Affected Pipelines. At a minimum, this\nprocess must include hydrostatic pressure testing of the Isolated Segments, must\nconsider all failure causes and must specify the use of one or more of the\nfollowing:\n1) ILI tools that are technically appropriate for assessing the pipeline system\nbased on the cause of Incident and that can reliably detect and identify\nanomalies;\n2) Close-interval surveys;\n3) Cathodic protection surveys, to include interference surveys in coordination\nwith other utilities (e.g. underground utilities, overhead power lines, etc.) in\nthe area;\n4) Coating surveys;\n5) Stress corrosion cracking surveys;\n6) Selective seam corrosion surveys; and\n7) Other tests, inspections, assessments, and evaluations appropriate for the\nfailure causes.\nNote: Respondent may use the results of previous tests, inspections, assessments,\nand evaluations if approved by the Director, provided the results of the tests,\ninspections, assessments, and evaluations are analyzed with regard to the factors\nknown or suspected to have caused the Incident.\nvi. Describe the inspection and repair criteria Respondent will use to prioritize,\nexcavate, evaluate, and repair anomalies, imperfections, and other identified\nintegrity threats. Include a description of how any defects will be graded and a\nschedule for repairs or replacement.\nvii. Based on the known history and condition of the Affected Pipelines, describe the\nmethods Respondent will use to repair, replace, or take other corrective measures\nto remediate the conditions associated with the Incident and to address other\nknown integrity threats along the Affected Pipelines. The repair, replacement, or\nother corrective measures must meet the criteria specified in (e)(vi) above.\nviii. Implement continuing long-term periodic testing and integrity verification\nmeasures to ensure the ongoing safe operation of the Affected Pipelines\nconsidering the results of the analyses, inspections, evaluations, and corrective\nmeasures undertaken pursuant to the Order.\nInclude a proposed schedule for completion of the RWP.\n\n\n\ng. h. Respondent must revise the RWP as necessary to incorporate new information obtained\nduring the failure investigation and remedial activities, to incorporate the results of\nactions undertaken pursuant to this Order, and to incorporate modifications required by\nthe Director.\ni. ii. iii. Submit any plan revisions to the Director for prior approval.\nThe Director may approve plan revisions incrementally.\nAll revisions to the RWP after it has been approved and incorporated by reference\ninto this Order will be fully described and documented in the CAO\nDocumentation Report.\nImplement the RWP as it is approved by the Director, including any revisions to the\n9. plan.\nInstrumented Leakage Survey. Within 30 days of receipt of this Order, Respondent must\nperform an aerial or ground instrumented leakage survey of the Affected Pipelines.\nRespondent must investigate all leak indications and remedy all leaks discovered.\nRespondent must submit documentation of this survey to the Director within 45 days of\nreceipt of this Order.\n10. Records Verification. Respondent must verify the records for the Affected Pipelines that\nwere used to establish the MAOP in accordance with § 192.619, including any adjustments\nneeded for the current class locations per §§ 192.609 and 192.611. Respondent must\nsubmit documentation of this records verification to the Director within 45 days of receipt\nof this Order.\n11. CAO Documentation Report (CDR). Respondent must create and revise, as necessary, a\nCAO Documentation Report (CDR). When Respondent has concluded all the items in this\nOrder it will submit the final CDR in its entirety to the Director. This will allow the\nDirector to complete a thorough review of all actions taken by Respondent with regards to\nthis Order prior to approving the closure of this Order. The intent is for the CDR to\nsummarize all activities and documentation associated with this Order in one document.\na. b. The Director may approve the CDR incrementally without approving the entire CDR.\nOnce approved by the Director, the CDR will be incorporated by reference into this\nOrder.\nc. The CDR must include, but is not necessarily limited to, the following:\ni. Table of Contents;\nii. iii. Summary of the Incident and the response activities;\nSummary of pipe data, material properties and all prior assessments of the\nAffected Pipelines;\niv. Summary of all tests, inspections, assessments, evaluations, and analysis required\nby the Order;\nv. vi. Summary of the mechanical and metallurgical testing as required by the Order;\nSummary of the RCFA with all root causes as required by the Order;\n\n\n\nvii. Documentation of all actions taken by Respondent to implement the RWP, the\nresults of those actions, and the inspection and repair criteria used;\nviii. Documentation of any revisions to the RWP including those necessary to\nincorporate the results of actions undertaken pursuant to this Order and whenever\nnecessary to incorporate new information obtained during the failure investigation\nand remedial activities;\nix. x. Lessons learned while completing this Order;\nA path forward describing specific actions Respondent will take on its entire\npipeline system as a result of the lessons learned from work on this Order; and\nxi. Appendices (if required).\nOther Requirements:\n12. Approvals. With respect to each submission that under this Order requires the approval of\nthe Director, the Director may: (a) approve, in whole or part, the submission; (b) approve\nthe submission on specified conditions; (c) modify the submission to cure any deficiencies;\n(d) disapprove in whole or in part, the submission, directing that Respondent modify the\nsubmission, or (e) any combination of the above. In the event of approval, approval upon\nconditions, or modification by the Director, Respondent shall proceed to take all action\nrequired by the submission as approved or modified by the Director. If the Director\ndisapproves all or any portion of the submission, Respondent must correct all deficiencies\nwithin the time specified by the Director and resubmit it for approval.\n13. Extensions of Time. The Director may grant an extension of time for compliance with any\nof the terms of this Order upon a written request timely submitted demonstrating good\ncause for an extension.\n14. Reporting. Submit quarterly reports to the Director that: (1) include all available data and\nresults of the testing and evaluations required by this Order; and (2) describe the progress\nof the repairs or other remedial actions being undertaken. The first quarterly report is due\non November 30, 2023. The Director may change the interval for the submission of these\nreports.\n15. Documentation of the Costs. It is requested but not required that Respondent maintain\ndocumentation of the costs associated with implementation of this Corrective Action Order.\nInclude in each monthly report submitted, the to-date total costs associated with: (1)\npreparation and revision of procedures, studies, and analyses; (2) physical changes to\npipeline infrastructure, including repairs, replacements and other modifications; and (3)\nenvironmental remediation, if applicable.\nBe advised that all material you submit in response to this enforcement action is subject to being\nmade publicly available. If you believe that any portion of your responsive material qualifies for\nconfidential treatment under 5 U.S.C. § 552(b), along with the complete original document you\nmust provide a second copy of the document with the portions you believe qualify for confidential\n\n\n\ntreatment redacted and an explanation of why you believe the redacted information qualifies for\nconfidential treatment under 5 U.S.C. § 552(b).\nIn your correspondence on this matter, please refer to “CPF No. 4-2023-007-CAO” and for each\ndocument you submit, please provide a copy in electronic format whenever possible. The actions\nrequired by this Order are in addition to and do not waive any requirements that apply to\nRespondent’s pipeline system under 49 C.F.R. Parts 190 through 199, under any other order issued\nto Respondent under authority of 49 U.S.C. Chapter 601, or under any other provision of federal\nor state law.\nRespondent may appeal in writing any decision of the Director to the Associate Administrator for\nPipeline Safety. Decisions of the Associate Administrator shall be final.\nFailure to comply with this Order may result in the assessment of civil penalties and in referral to\nthe Attorney General for appropriate relief in United States District Court pursuant to\n49 U.S.C. § 60120.\nThe terms and conditions of this Order are effective upon service in accordance with 49 C.F.R.\n§ 190.5.\n_________________________________ ___\nOctober 13, 2023_____\nAlan K. Mayberry Date Issued\nAssociate Administrator\nfor Pipeline Safety\n\n4202300","truncated":true,"body_characters":81614}