{"operation":"document","citation":"PLD19FR002","title":"Enbridge Inc. Natural Gas Transmission Pipeline Rupture and Fire","source_type":"incident","agency":"National Transportation Safety Board","status":"current","official":true,"published_on":"2022-09-26","effective_on":"2019-08-01","summary":"Accident. in Danville, KY, USA. on 2019-08-01. Texas Eastern Transmission. Rupture/fire","machine_formats":{"json":"https://regulus.evalyn.ai/document/ntsb-case-pld19fr002.json","markdown":"https://regulus.evalyn.ai/document/ntsb-case-pld19fr002.md"},"app_url":"https://regulus.evalyn.ai/document/ntsb-case-pld19fr002","source_url":"https://www.ntsb.gov/investigations/Pages/PLD19FR002.aspx","body":"NTSB investigation PLD19FR002.\n\nEvent Type: Accident\n\nEvent Date: 2019-08-01\n\nEvent City: Danville\n\nEvent State Or Region: KY\n\nEvent Country: USA\n\nPipeline Operator: Texas Eastern Transmission\n\nPipeline Type: Gas Transmission - Regulated\n\nAccident Type: Rupture/fire\n\nCompletion Status: Completed\n\nReport Number: TBD\n\nReport Date: 2022-08-15\n\nProbable cause: The NTSB determines that the probable cause of the August 1, 2019 rupture of an Enbridge, Inc. natural gas transmission pipeline and resulting fire was the combination of a pre-existing hard spot (a manufacturing defect), degraded coating, and ineffective cathodic protection applied following a 2014 gas flow reversal project, which resulted in hydrogen induced cracking at the outer surface of Line 15 and the subsequent failure of the pipeline. Contributing to the accident was the 2014 gas flow reversal project that increased external corrosion and hydrogen evolution. Also contributing to this accident was Enbridge’s integrity management program, which did not accurately assess the integrity of the pipeline or estimate the risk from interacting threats.\n\nTier1Name: Emergency response\n\nTier2Name: Fire (post-release)\n\nTier1Name: System shutdown\n\nTier2Name: Emergency response\n\nTier1Name: System operating\n\nTier2Name: Product leak/release\n\nTier1Name: System operating\n\nTier2Name: Pipe structural malfunction/failure\n\nFinding Tier1Name: Organizational\n\nFinding Tier2Name: Support/oversight/monitoring\n\nFinding Tier3Name: Safety programs\n\nFinding Modifier Name: Pipeline operator\n\nFinding Report Text: Organizational - Support/oversight/monitoring - Safety programs - Pipeline operator\n\nFinding Tier1Name: Organizational\n\nFinding Tier2Name: Support/oversight/monitoring\n\nFinding Tier3Name: Safety programs\n\nFinding Modifier Name: Federal agency\n\nFinding Report Text: Organizational - Support/oversight/monitoring - Safety programs - Federal agency\n\nFinding Tier1Name: Pipeline\n\nFinding Tier2Name: Pipeline operation/capability\n\nFinding Tier3Name: Pipeline temp/pressure/flow parameter(s)\n\nFinding Modifier Name: Design\n\nFinding Report Text: Pipeline - Pipeline operation/capability - Pipeline temp/pressure/flow parameter(s) - Design\n\nFinding Tier1Name: Pipeline\n\nFinding Tier2Name: Pipeline structure\n\nFinding Tier3Name: Pipe coatings/anti-corrosion\n\nFinding Modifier Name: Damaged/degraded\n\nFinding Report Text: Pipeline - Pipeline structure - Pipe coatings/anti-corrosion - Damaged/degraded\n\nFinding Tier1Name: Pipeline\n\nFinding Tier2Name: Pipeline structure\n\nFinding Tier3Name: Pipe\n\nFinding Modifier Name: Fatigue/wear/corrosion\n\nFinding Report Text: Pipeline - Pipeline structure - Pipe - Fatigue/wear/corrosion\n\nFinding Tier1Name: Personnel\n\nFinding Tier2Name: Experience/knowledge\n\nFinding Tier3Name: Training\n\nFinding Tier4Name: (general)\n\nFinding Modifier Name: SCADA operations personnel\n\nFinding Report Text: Personnel - Experience/knowledge - Training - SCADA operations personnel\n\nFinding Tier1Name: Pipeline\n\nFinding Tier2Name: Pipeline operation/capability\n\nFinding Tier3Name: Pipeline integrity/capacity\n\nFinding Modifier Name: Inadequate inspection\n\nFinding Report Text: Pipeline - Pipeline operation/capability - Pipeline integrity/capacity - Inadequate inspection\n\nFinding Tier1Name: Pipeline\n\nFinding Tier2Name: Pipeline structure\n\nFinding Tier3Name: Pipe\n\nFinding Modifier Name: Failure\n\nFinding Report Text: Pipeline - Pipeline structure - Pipe - Failure\n\nOfficial NTSB investigation data. NTSB findings determine probable cause and make safety recommendations; they do not adjudicate civil liability or regulatory violations.\n\nWhat Happened\nOn August 1, 2019, at 1:23 a.m. local time, an Enbridge Inc. 30-inch natural gas transmission pipeline ruptured in Danville, Kentucky, releasing about 101.5 million cubic feet of natural gas that ignited. The accident resulted in 1 fatality, 6 injuries, and the evacuation of over 75 people. Five residences were destroyed by resulting structure fires, and an additional 14 were damaged. A nearby railroad track was also damaged, and over 30 acres of land were burned.\nAt 1:26 a.m., numerous local emergency response agencies were dispatched to the accident; the Lincoln County Fire Protection District was the first to arrive at 1:37 a.m. The fire department and other emergency responders focused on evacuations and medical transport while Enbridge crews worked to isolate and shut down the pipeline. At 2:19 a.m., the ruptured pipeline segment was isolated. By 4:13 a.m., all fire suppression activities had concluded.\n\nWhat We Found\nThe probable cause of the August 1, 2019, Enbridge Inc. pipeline rupture and resulting fire was the combination of a pre-existing hard spot (a manufacturing defect), degraded coating, and ineffective cathodic protection applied following a 2014 gas flow reversal project, which resulted in hydrogen induced cracking at the outer surface of Line 15 and the subsequent failure of the pipeline. Contributing to the accident was the 2014 gas flow reversal project that increased external corrosion and hydrogen evolution. Also contributing to this accident was Enbridge’s integrity management program, which did not accurately assess the integrity of the pipeline or estimate the risk from interacting threats.\n\nPIR-22-02\n<<<PAGE 1>>>\n\nIssued: August 15, 2022 Pipeline Investigation Report: NTSB/PIR-22/02\nEnbridge Inc. Natural Gas Transmission\nPipeline Rupture and Fire\nDanville, Kentucky\nAugust 1, 2019\nAbstract: This report discusses the August 1, 2019, rupture of an Enbridge Inc.\n30-inch natural gas transmission pipeline in Danville, Kentucky, which released about\n101.5 million cubic feet of natural gas that ignited. The accident resulted in 1 fatality,\n6 injuries, and the evacuation of over 75 people, as well as property damage in the\nsurrounding area. Safety issues identified in this report include nonconservative\nassumptions used to calculate the potential impact radius, incomplete evaluation of\nthe risks caused by a change of gas flow direction, limitations in data analysis related\nto in-line inspection tool usage, incomplete assessment of threats and threat\ninteractions, and missed opportunities in training and requalification practices. Three\nrecommendations are made to Enbridge Inc., and three recommendations are made\nto the Pipeline and Hazardous Materials Safety Administration.\n\n<<<PAGE 2>>>\n\nPipeline Investigation Report\nNTSB/PIR-22/02\nContents\nFigures ................................................................................................................. iv\nTables .................................................................................................................... v\nAbbreviations and Acronyms ............................................................................... vi\nExecutive Summary ..............................................................................................vii\nWhat Happened.............................................................................................................. vii\nWhat We Found .............................................................................................................. vii\nWhat We Recommended ............................................................................................. viii\n1. Factual Information .......................................................................................... 1\n1.1 Accident Description ............................................................................................... 1\n1.2 Emergency Response .............................................................................................. 2\n1.2.1 Enbridge Response ...................................................................................... 2\n1.2.2 Local Emergency Response ........................................................................ 3\n1.3 Injuries and Damages from the Gas Fire ............................................................... 4\n1.4 Enbridge Natural Gas Systems and Pipeline Specifications ............................... 5\n1.4.1 Texas Eastern Transmission, LP, Line 15 .................................................... 5\n1.4.2 Danville Compressor Station ...................................................................... 7\n1.4.3 Gas Control Center....................................................................................... 7\n1.5 Postaccident Pipeline Examination and Testing .................................................. 8\n1.5.1 On-Site Visual Examinations ........................................................................ 8\n1.5.2 Microscope Examination of the Fracture Origin .................................... 10\n1.5.3 Microhardness Testing ............................................................................... 11\n1.5.4 Microstructure ............................................................................................. 12\n1.5.5 Other Examinations .................................................................................... 12\ni\n\n<<<PAGE 3>>>\n\nPipeline Investigation Report\nNTSB/PIR-22/02\n1.6 Line 15 Incident History ......................................................................................... 13\n1.6.1 2003 Rupture ............................................................................................... 13\n1.6.2 2014 to 2017 Operational Modifications ................................................ 14\n1.6.3 2019 Danville Compressor Station Emergency Shutdown ................... 15\n1.7 Enbridge Procedures, Operations, and Maintenance ...................................... 16\n1.7.1 Company Background ............................................................................... 16\n1.7.2 Emergency Response Plan ........................................................................ 17\n1.7.3 Cathodic Protection ................................................................................... 18\n1.8 Integrity Management ........................................................................................... 21\n1.8.1 High Consequence Area Identification ................................................... 23\n1.8.2 Threat Identification and Interaction ........................................................ 24\n1.8.3 Risk Assessment .......................................................................................... 26\n1.8.4 Integrity Assessment .................................................................................. 26\n1.8.5 Hard Spot In-Line Inspection Data Analysis ............................................ 28\n1.8.6 Data Validation ............................................................................................ 29\n1.8.7 Response and Repair ................................................................................. 30\n1.8.8 Program Performance ................................................................................ 30\n1.8.9 Recent Integrity Management Program Changes .................................. 31\n1.9 Postaccident Actions ............................................................................................. 32\n2. Analysis .......................................................................................................... 34\n2.1 Introduction ............................................................................................................ 34\n2.2 The Accident ........................................................................................................... 35\n2.3 Calculation of the Potential Impact Radius ......................................................... 37\n2.4 Management of Gas Flow Reversal ..................................................................... 39\nii\n\n<<<PAGE 4>>>\n\nPipeline Investigation Report\nNTSB/PIR-22/02\n2.5 In-Line Inspection Tool and Data Analyses ......................................................... 40\n2.6 Threat Assessment and Interactions .................................................................... 42\n2.7 Training and Requalification Practices ................................................................ 44\n3. Conclusions .................................................................................................... 45\n3.1 Findings .................................................................................................................... 45\n3.2 Probable Cause ....................................................................................................... 46\n4. Recommendations ......................................................................................... 47\n4.1 New Recommendations ......................................................................................... 47\nAppendix A: Investigation .................................................................................. 49\nAppendix B: Consolidated Recommendation Information ................................ 50\nReferences ........................................................................................................... 53\niii\n\n<<<PAGE 5>>>\n\nPipeline Investigation Report\nNTSB/PIR-22/02\nFigures\nFigure 1. Aerial view of the Indian Camp Subdivision overlaid on Google Earth image.\n.................................................................................................................................................. 1\nFigure 2. Process flow diagram for pipeline isolation. ...................................................... 2\nFigure 3. Homes of decedent and rescued couple, rupture location, and gas flame\ndirection. .................................................................................................................................. 5\nFigure 4. Crater and ground bedding at rupture site. ....................................................... 9\nFigure 5. Ejected pipeline segment. .................................................................................. 10\nFigure 6. East face of the fracture origin. ........................................................................... 11\nFigure 7. Map of Texas Eastern Transmission pipelines. (Courtesy Enbridge.) ........... 17\nFigure 8. Map of the right of way for Lines 10, 15, and 25. ............................................. 19\nFigure 9. Voltage outputs at Goodnight and Harris Creek rectifiers. ............................ 20\nFigure 10. Integrity management process flow. ............................................................... 22\nFigure 11. Human-occupancy buildings within the potential impact radius. (Courtesy\nof Enbridge.) ......................................................................................................................... 24\niv\n\n<<<PAGE 6>>>\n\nPipeline Investigation Report\nNTSB/PIR-22/02\nTables\nTable 1. Enbridge emergency response actions ................................................................ 3\nTable 2. Local emergency response actions ....................................................................... 4\nTable 3. Recent ownership history for Texas Eastern Transmission ................................. 6\nTable 4. Pipeline specifications of Line 15 at the rupture origin ...................................... 7\nTable 5. External metal loss anomalies identified in ILI runs........................................... 21\nTable 6. Integrity assessments performed on the ruptured pipeline segment between\n2003 and 2019 ...................................................................................................................... 27\nv\n\n<<<PAGE 7>>>\n\nPipeline Investigation Report\nNTSB/PIR-22/02\nAbbreviations and Acronyms\nAPI American Petroleum Institute\nCFR Co de of Federal Regulations\nCS compressor station\nDEGT Duke Energy Gas Transmission\nHCA high consequence area\nHSMFL hard spot magnetic flux leakage\nILI in-line inspection\nIM integrity management\nL15 VS4 assessment segment “Line 15 Valve Section 4”\nLCFPD Lincoln County Fire Protection District\nMAOP maximum allowable operating pressure\nNTSB National Transportation Safety Board\nPHMSA Pipeline and Hazardous Materials Safety\nAdministration\nPIR potential impact radius\nP-PIC Process Performance Improvement Consultants, LLC\npsig pounds per square inch, gauge\nSCADA Supervisory Control and Data Acquisition\nSTD Standard\nTET Texas Eastern Transmission, LP\nvi\n\n<<<PAGE 8>>>\n\nPipeline Investigation Report\nNTSB/PIR-22/02\nExecutive Summary\nWhat Happened\nOn August 1, 2019, at 1:23 a.m. local time, an Enbridge Inc. (Enbridge) 30-inch\nnatural gas transmission pipeline ruptured in Danville, Kentucky, releasing about\n101.5 million cubic feet of natural gas that ignited. The accident resulted in 1 fatality,\n6 injuries, and the evacuation of over 75 people. Five residences were destroyed by\nresulting structure fires, and an additional 14 were damaged. A nearby railroad track\nwas also damaged, and over 30 acres of land were burned.\nAt 1:26 a.m., numerous local emergency response agencies were dispatched\nto the accident; the Lincoln County Fire Protection District was the first to arrive at\n1:37 a.m. The fire department and other emergency responders focused on\nevacuations and medical transport while Enbridge crews worked to isolate and shut\ndown the pipeline. At 2:19 a.m., the ruptured pipeline segment was isolated. By\n4:13 a.m., all fire suppression activities had concluded.\nWhat We Found\nWe found that the combination of a pre-existing hard spot (a manufacturing\ndefect), degraded coating, and ineffective cathodic protection applied following a\n2014 gas flow reversal project resulted in hydrogen-induced cracking at the outer\nsurface of the pipeline and its subsequent failure. We also found that the Pipeline and\nHazardous Materials Safety Administration’s (PHMSA’s) equation for determining the\npotential impact radius of a pipeline rupture is based on assumptions that are\ninconsistent with findings from recent natural gas ruptures and human response data;\nthus, high consequence areas determined using the equation do not include the full\narea at risk.\nEnbridge and Spectra Energy Partners LP did not effectively identify,\ninvestigate or manage the impact of a 2014 gas flow reversal project for the level of\nhydrogen evolution, or generation, in the pipeline surface, which ultimately\ncontributed to the failure of the pipeline. The extent of hard spots on pipelines\nevaluated using the hard spot magnetic flux leakage in-line inspection tool is likely\nunknown because of the limitations of the tool and analysis techniques found during\nthis investigation. Further, insufficient data were available to support Enbridge’s\nclassification of the threat of hard spots in the accident pipeline as inactive. Enbridge\nunderestimated the risk posed by hard spots because its processes and procedures\nwere inconsistent with PHMSA guidance and industry knowledge of hard spot threat\ninteractions.\nEnbridge also missed an opportunity to address a lack of knowledge displayed\nby the Danville compressor station operator in an emergency shutdown earlier in\nvii\n\n<<<PAGE 9>>>\n\nPipeline Investigation Report\nNTSB/PIR-22/02\n2019; addressing this may have reduced the delay in the operator’s response at the\nstation on the morning of the accident.\nWe determined that the probable cause of the August 1, 2019, Enbridge\npipeline rupture and resulting fire was the combination of a pre-existing hard spot (a\nmanufacturing defect), degraded coating, and ineffective cathodic protection applied\nfollowing a 2014 gas flow reversal project, which resulted in hydrogen-induced\ncracking at the outer surface of Line 15 and the subsequent failure of the pipeline.\nContributing to the accident was the 2014 gas flow reversal project that increased\nexternal corrosion and hydrogen evolution. Also contributing to this accident was\nEnbridge’s integrity management program, which did not accurately assess the\nintegrity of the pipeline or estimate the risk from interacting threats.\nWhat We Recommended\nAs a result of this investigation, we made a recommendation to PHMSA to\nrevise the regulations regarding potential impact radius methodology based on data\nfrom recent natural gas pipeline ruptures and human response considerations. We\nalso recommended that PHMSA advise natural gas transmission operators on the\ncircumstances of this accident, the need to evaluate the risks associated with flow\nreversal projects, the impacts of such projects on hydrogen-induced cracking, the\npossible data limitations associated with the use of in-line inspection tools and\nanalysis used in hard spot management programs, and the need to follow industry\nbest practices when conducting in-line inspection data analysis.\nWe made recommendations to Enbridge to evaluate the effectiveness of its\ncorrosion control equipment and infrastructure following a major change in\noperations, like a gas flow reversal; modify its integrity management program to\nbetter address threats and threat interactions; and require disqualification, remedial\ntraining, and/or requalification of covered tasks whenever an employee does not\nfollow procedures when responding to an emergency shutdown, rupture, or other\nabnormal operation.\nviii\n\n<<<PAGE 10>>>\n\nPipeline Investigation Report\nNTSB/PIR-22/02\n1. Factual Information\n1.1 Accident Description\nOn August 1, 2019, at 1:23 a.m. local time, a 30-inch-diameter natural gas\ntransmission pipeline, Line 15, owned and operated by Enbridge Inc. (Enbridge),\nruptured near Danville, Kentucky.1 As a result of the rupture, 1 person was fatally\ninjured, 6 people were hospitalized, and over 75 residents were evacuated from the\nIndian Camp Subdivision, a residential community. The rupture released about\n101.5 million cubic feet of natural gas and ejected a 33.2-foot-long section of pipeline\nthat landed about 481 feet southwest of the rupture site. The releasing gas ignited\nand burned. Five residences in the subdivision were destroyed by fires, and an\nadditional 14 were damaged. (See figure 1.) A nearby railroad track owned and\noperated by the Norfolk Southern Corporation sustained fire damage.\nFigure 1. Aerial view of the Indian Camp Subdivision overlaid on Google Earth image.\nEnbridge personnel completed isolation of the affected pipeline segment at\n2:19 a.m., while a Lincoln County Sheriff’s Office deputy sheriff and the Lincoln\n1 (a) Visit ntsb.gov to find additional information in the public docket for this NTSB accident\ninvestigation (case number PLD19FR002). Use the CAROL Query to search safety recommendations\nand investigations. (b) The ruptured pipeline was one of three parallel pipelines traversing the area.\nThe pipelines will be discussed in more detail in section 1.4.1. (c) All times in this report are local time.\n1\n\n<<<PAGE 11>>>\n\nPipeline Investigation Report\nNTSB/PIR-22/02\nCounty Fire Protection District worked to rescue and evacuate residents and minimize\nthe spread of the fire. The grass fires in the surrounding area were extinguished at\n3:20 a.m., and the structure fires were extinguished at 4:13 a.m.\n1.2 Emergency Response\n1.2.1 Enbridge Response\nAn Enbridge employee received a call at 1:23 a.m. about the event from a\nfriend who lived near the rupture site. Enbridge’s gas control center received an\ninformational pressure rate-of-change alarm on the discharge (south) side of the\nDanville compressor station (CS) on Line 15 at 1:24 a.m.\n2 This alarm indicated a\npressure drop in the pipeline of about 105 pounds per square inch (psi) in 1 minute.\nAt 1:25 a.m. the Enbridge gas control center received a second pressure\nrate-of-change alarm.\nTo isolate the affected pipeline segment, Enbridge personnel needed to close\nvalves manually at the Danville CS (valve 15-393) and at a valve station located near\nHighway 49 (valve 15-382). (See figure 2).\nFigure 2. Process flow diagram for pipeline isolation.\nAt 1:28 a.m., the Enbridge’s area supervisor received a call at home about the\nrupture from the employee first notified at 1:23 a.m. The supervisor directed that\nemployee to the Highway 49 valve station to close valve 15-382. Then the area\nsupervisor called the station operator at the Danville CS at 1:35 a.m. and instructed\nhim to close valve 15-393 to isolate the damaged pipeline segment on the north side\nof the rupture. Although an on-duty station operator was present, saw a visible fire\n2 Compressor stations increase the pressure of gas in a pipeline by compressing it. The discharge\nside of a compressor station is the higher-pressure output side. The suction side of a compressor\nstation is the lower-pressure input side. The Danville CS was the closest compressor station to the\nrupture site, located 4.1 miles to the north.\n2\n\n<<<PAGE 12>>>\n\nPipeline Investigation Report\nNTSB/PIR-22/02\nfrom the station, and saw a low-pressure alarm at the CS, he did not act to close the\nmanual valve at the CS until instructed by the area supervisor. The station operator\nmanually closed valve 15-393 at 1:39 a.m., isolating the affected pipeline segment on\nthe north side of the rupture.\nThe Enbridge employee sent to manually close valve 15-382 arrived at the\nHighway 49 valve station at 2:13 a.m. and confirmed valve 15-382 was the correct\nvalve to close by checking Enbridge’s Stanford Area Emergency Response Manual\n(2015), which was in his company vehicle. The employee closed valve 15-382,\ncompleting isolation of the ruptured segment at 2:19 a.m. The total time from the\nrupture to isolation was 56 minutes. Table 1 provides a detailed timeline of\nEnbridge’s emergency response actions.\nTable 1. Enbridge emergency response actions\nTime Activity\n1:23 a.m. Enbridge employee receives notification of rupture from friend\n1:24 a.m. First alarm received in Enbridge gas control center\n1:25 a.m. Second alarm received in Enbridge gas control center\n1:26 a.m. Enbridge gas control center attempts to contact Danville station operator\n1:27 a.m. Enbridge gas control center receives report of accident from the public\n1:28 a.m. Enbridge area supervisor dispatches employee to Highway 49 valve station\n1:29 a.m. Danville station operator notifies Enbridge gas control center of fireball\n1:30 a.m. Enbridge gas control center shuts off compressors at an upstream compressor station\n1:30 a.m. Enbridge area supervisor notifies gas control center of valve closures required for isolation\n1:35 a.m. Enbridge area supervisor instructs Danville station operator to close valve 15-393\n1:39 a.m. Danville station operator manually closes valve 15-393\n2:13 a.m. Enbridge employee arrives at Highway 49 valve station\n2:19 a.m. Enbridge employee manually closes valve 15-382 at Highway 49 valve station, completing isolation\n1.2.2 Local Emergency Response\nAt 1:23 a.m., Bluegrass 911 Central Communications Center (Bluegrass 911)\nreceived a call from a motorist traveling by the accident site, who reported an\nexplosion and massive fire.3 Shortly after, Bluegrass 911 requested emergency\nresponse to the accident site. At 1:35 a.m., an engine and a rescue/brush truck were\ndispatched from Fire Station 3 of the Lincoln County Fire Protection District (LCFPD),\nthe closest station. Additionally, mutual aid was provided by several adjacent\nemergency services jurisdictions, including the Stanford Fire Department, Boyle\nCounty Fire Department, and Danville Police Department. The entire emergency\nresponse totaled 81 firefighters, 10 engines and 21 trucks. All structure fires were\n3 Bluegrass 911 received 71 additional reports of the accident from the public after this initial call.\n3\n\n<<<PAGE 13>>>\n\nPipeline Investigation Report\nNTSB/PIR-22/02\nextinguished by 4:13 a.m. Table 2 provides a detailed timeline of local emergency\nresponse actions.\nTable 2. Local emergency response actions\nTime Activity\n1:23 a.m. Initial report to Bluegrass 911\n1:26 a.m. Bluegrass 911 requests response to the accident site\n1:35 a.m. Engine and truck dispatched from LCFPD Fire Station 3\n1:37 a.m. LCFPD arrives at accident site\n1:39 a.m. LCFPD Assistant Chief assumes incident commander role\n1:40 a.m. Command post established at Indian Camp Road and Route 127\n2:19 a.m. Ruptured pipeline segment isolated\n2:56 a.m. Suppression of grass fires begins\n3:00 a.m. House-to-house searches performed by LCFPD, no individuals found\n3:20 a.m. Surrounding grass fires extinguished\n3:29 a.m. LCFPD checks area for natural gas with gas detectors, none observed\n3:57 a.m. Suppression of structure fires begins\n4:13 a.m. Structure fires extinguished\nA part-time, off-duty Lincoln County Sheriff’s Office deputy sheriff also\nresponded to the accident site. While approaching the source of the natural gas fire,\nthe deputy observed a man lying on the front porch of a burning residence about\n480 feet from the rupture site. The deputy placed the injured man and the man’s wife,\nwho he rescued from just inside the door to the house, in the police cruiser. In a\npostaccident interview with the National Transportation Safety Board (NTSB), the\ndeputy described the heat in the area of the accident as “more than I [could] handle.“\nThe deputy also attempted to render aid to a woman lying on the ground nearby but\ndetermined she was deceased and, due to the intense heat, was unable to recover\nher. The deputy left the area with the two evacuees and transferred them to nearby\nambulance personnel.\n1.3 Injuries and Damages from the Gas Fire\nAfter rescuing the two injured individuals, the deputy sheriff drove to a local\nmedical trauma center to have a minor burn injury treated. Three other residents of\nthe subdivision were also transported to the facility for treatment. All five of the\ninjured residents and the deputy sheriff were subsequently released after receiving\nmedical care.\nThe home of the deceased was located about 310 feet south of the rupture\nlocation. The deceased individual was about 640 feet south of the natural gas fire\nwhen she was found by the deputy sheriff.\n4\n\n<<<PAGE 14>>>\n\nPipeline Investigation Report\nNTSB/PIR-22/02\nFive residences were destroyed by resulting structure fires. Fourteen other\nresidences suffered property damage to various degrees; some were 1,100 feet from\nthe rupture crater. The gas flame direction, as shown by the darkened area of soil\nindicated with a black arrow in figure 3, was oriented along a true bearing of about\n80°, or just north of due east. This flame direction was consistent with the direction of\nthe pipeline at the rupture location.\nFigure 3. Homes of decedent and rescued couple, rupture location, and gas flame direction.\n1.4 Enbridge Natural Gas Systems and Pipeline Specifications\n1.4.1 Texas Eastern Transmission, LP, Line 15\nThe Enbridge asset involved in this accident, Texas Eastern Transmission LP\n(TET), a natural gas transmission pipeline system, connects the Gulf Coast with the\nnortheastern United States. TET is a wholly owned subsidiary of Spectra Energy\nPartners LP (Spectra), which was purchased by Enbridge in 2017. Table 3 lists the\nrecent ownership history for TET.\n5\n\n<<<PAGE 15>>>\n\nPipeline Investigation Report\nNTSB/PIR-22/02\nTable 3. Recent ownership history for Texas Eastern Transmission\nOwner of TET Time Period\nTexas Eastern Corporation January 30, 1947 – June 28, 1989\nPanhandle Eastern Corporation June 29, 1989 – July 28, 1994\nPanhandle Eastern Corporation/PanEnergy Corp July 29, 1994 – April 15, 2001\nDuke Energy Gas Transmission Corporation April 16, 2001 – January 1, 2007\nSpectra Energy Corp January 2, 2007 – October 31, 2013\nSpectra Energy Partners, Limited Partnership November 1, 2013 – present\nEnbridge Inc. February 27, 2017 – present\nAt the accident location, three parallel Enbridge pipelines (lines) transport\nnatural gas through a common right-of-way: Line 10, Line 15, and Line 25. The\nrupture on TET Line 15 occurred at milepost 423.4.4 The impacted TET section was\nknown as Tompkinsville to Danville and was located within the Stanford Area. The\nDanville CS is located at milepost 408.5 and the Highway 49 valve station was located\nat milepost 427.5.\nAt the time of the rupture, gas in Line 15 was flowing south from the Danville\nCS to the Tompkinsville CS at 925 pounds per square inch, gauge (psig), which was\nless than the maximum allowable operating pressure (MAOP) of 936 psig.5 According\nto Enbridge, the pressure on Line 15 between the Tompkinsville CS and the Danville\nCS did not exceed the MAOP in the 5 years before the accident.\nThe external protective coating type for Line 15 in the area of the rupture was coal tar\nenamel.6 Other pipeline specifications for Line 15 are shown in table 4.\n4 A milepost is a unit of measure used to define the location on a pipeline relative to a chosen\nstarting point in miles and fractions of miles.\n5 Title 49 Code of Federal Regulations ( CFR ) Part 192.619, Maximum allowable operating\npressure: Steel or plastic pipelines, specifies how the maximum allowable operating pressure is\ndetermined.\n6 Coal tar enamel , also called coal tar wrap, was a coating commonly used in the 1950s. Hot tar\nformulated from coal tar pitches and inert fillers was applied to the pipeline exterior over a primer.\nOften, it was then covered with a fiberglass mesh and a felt wrap. Much of this original coating is still\npresent on transmission pipelines across the United States, including on Line 15.\n6\n\n<<<PAGE 16>>>\n\nPipeline Investigation Report\nNTSB/PIR-22/02\nTable 4. Pipeline specifications of Line 15 at the rupture origin\nPipeline Specification Value\nDiameter 30-inch\nMaterial Carbon Steel\nGrade/Specified Minimum Yield Strength1 X-52/52,000 psi\nLong Seam Weld Electric Flash-Welded\nManufacturer A. O. Smith Corporation\nYear Manufactured 1957\nYear Constructed 1958\nWall Thickness 0.375 inches\nFlow Direction (at time of rupture) South\nClass Location2 2\nMAOP, south flow 936 psig\nOperating Pressure (at time of rupture) 925 psig\nCS Discharge Temperature (at time of rupture) 115ºF\nSoil Type Shale\nCathodic Protection Method Impressed Current\n1 American Petroleum Institute 5LX defines specific grades of carbon steel pipeline, each with a minimum yield\nstrength. The higher the grade of the pipeline, the higher the strength of the steel used to manufacture that pipeline.\n2 Title 49 Code of Federal Regulations 192.5 defines class locations, with four class locations representing different\npopulation levels present near a pipeline. Class 4 areas have the highest populations around them and present the highest risk,\nwhile Class 1 areas present the lowest relative risk.\n1.4.2 Danville Compressor Station\nThe Danville CS was the closest compressor station to the rupture site, located\n4.1 miles to the north. The Danville CS is manned 24 hours a day, 365 days a year, by\na station operator working a 12-hour shift. The station operator is supervised by an\narea supervisor.7 Station operators perform physical walkthroughs of the station,\nevaluate Supervisory Control and Data Acquisition (SCADA) information at a\ncomputer, and respond to various types of emergencies, including emergency\nshutdowns or valve isolations of the system.8\n1.4.3 Gas Control Center\nEnbridge’s gas control center for its natural gas transmission pipelines is in\nHouston, Texas, and is the central location for monitoring and control of pipeline\n7 The area supervisor oversees the Stanford Area segment of pipe and manages 15 employees,\nincluding 4 station operators.\n8 Supervisory Control and Data Acquisition (SCADA) is a computer system for gathering and\nanalyzing real-time data. SCADA systems are used in the pipeline industry to monitor and control\npipeline systems. Station operators control and monitor a large amount of data and systems at the\nstation. There are almost 2,500 distinct SCADA inputs at the Danville CS.\n7\n\n<<<PAGE 17>>>\n\nPipeline Investigation Report\nNTSB/PIR-22/02\noperations. The gas control center is staffed 24 hours a day, 365 days a year, by six\ngas controllers working in 12-hour shifts and supervised by personnel within the gas\ncontrol center.\nGas controllers monitor operating conditions, such as line pressure, flow rate,\ntemperature, and gas composition. Depending on the data source, gas controllers\ncan look at data on an instantaneous, per minute, or hourly basis.\nGas controllers have authority to take immediate action in the event of an\nemergency, including a pipeline rupture. They notify the public and emergency\nresponse agencies when a potential accident is reported through their central phone\nline. The gas control center also coordinates information to and from the field during\nan emergency response, keeping track of which personnel are responding, where\nthey are, and what actions they are taking. Gas controllers are also able to operate\nvalves equipped for remote closure from the gas control center. Most valves on Line\n15 require manual operation, including valves 15-382 and 15-393 on either side of\nthe rupture.\n1.5 Postaccident Pipeline Examination and Testing\n1.5.1 On-Site Visual Examinations\nA crater was located in the area of the rupture; the crater and ground bedding\nunder the pipe consisted of soil and broken pieces of shale. (See figure 4.)\n8\n\n<<<PAGE 18>>>\n\nPipeline Investigation Report\nNTSB/PIR-22/02\nFigure 4. Crater and ground bedding at rupture site.\nThe NTSB’s on-scene examination of the ejected pipeline segment revealed\nthat most of the external coal tar coating was consumed by fire, leaving large regions\nof the external pipe surface bare. The fracture face of the ejected segment exhibited\nchevron fracture features, helping investigators locate the origin of the fracture.\n9\nFigure 5 shows the origin of the fracture as indicated by the brackets; the arrows\nindicate the general direction of fracture propagation.\n9 C hevron features , also known as a river pattern, is a fractographic pattern of marks that look like\nnested letters “V” or herringbone. The points of the chevrons can be traced back to the fracture origin.\n9\n\n<<<PAGE 19>>>\n\nPipeline Investigation Report\nNTSB/PIR-22/02\nFigure 5. Ejected pipeline segment.\nWhile on-site, the NTSB cut the ejected pipe section into three pieces to\nfacilitate shipping and handling. The exposed fractured ends of the pipe, located\nwithin the rupture crater, were cut at the border of the crater. The pipe sections were\ncrated and shipped to the NTSB Materials Laboratory for testing.\n1.5.2 Microscope Examination of the Fracture Origin\nThe NTSB Materials Laboratory examination of the fracture faces from the\nejected pipe revealed that the fracture originated at the outer surface, as indicated in\nfigure 6. The origin of the fracture and an area extending below it contained a flat\nregion with a rough texture, shown enclosed by a yellow line. Fracture propagation\nwas in the general direction indicated by the arrows.\n10 The origin of the fracture\nshowed no evidence of a gouge or dent and did not originate from a weld. The\nlength of the origin at the outer surface measured about 0.8 inches, and shear lips\nextended from both ends.11 The fracture face at the inner surface (opposite the\n10 Details of the fracture examination can be found in the NTSB Materials Laboratory Factual\nReport No. 19 -064 , February 6, 2020, in the docket for this accident.\n11 A shear lip is a precise 45° lip of metal around the perimeter of a ductile overstress fracture area.\n10\n\n<<<PAGE 20>>>\n\nPipeline Investigation Report\nNTSB/PIR-22/02\nfracture origin) contained a minor shear lip, indicating the fracture did not start at the\ninner surface of the pipe. The fracture areas located outside of the north and south\nends of the flat region were on a slant plane and contained a chevron pattern,\nconsistent with overstress separation.\nFigure 6. East face of the fracture origin.\nA detailed scanning electron microscope examination of the fracture face\nrevealed that the origin exhibited intergranular fracture features, which came from\nlocalized embrittlement caused by exposure to hydrogen.\n12 The amount of\nintergranular fracture features decreased toward the inner surface of the pipe.\n1.5.3 Microhardness Testing\nTwo metallurgical cross sections, one longitudinal and one circumferential,\nwere mad","truncated":true,"body_characters":141065}