# Enbridge Inc. Natural Gas Transmission Pipeline Rupture and Fire - **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. Event Type: Accident Event Date: 2019-08-01 Event City: Danville Event State Or Region: KY Event Country: USA Pipeline Operator: Texas Eastern Transmission Pipeline Type: Gas Transmission - Regulated Accident Type: Rupture/fire Completion Status: Completed Report Number: TBD Report Date: 2022-08-15 Probable 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. Tier1Name: Emergency response Tier2Name: Fire (post-release) Tier1Name: System shutdown Tier2Name: Emergency response Tier1Name: System operating Tier2Name: Product leak/release Tier1Name: System operating Tier2Name: Pipe structural malfunction/failure Finding Tier1Name: Organizational Finding Tier2Name: Support/oversight/monitoring Finding Tier3Name: Safety programs Finding Modifier Name: Pipeline operator Finding Report Text: Organizational - Support/oversight/monitoring - Safety programs - Pipeline operator Finding Tier1Name: Organizational Finding Tier2Name: Support/oversight/monitoring Finding Tier3Name: Safety programs Finding Modifier Name: Federal agency Finding Report Text: Organizational - Support/oversight/monitoring - Safety programs - Federal agency Finding Tier1Name: Pipeline Finding Tier2Name: Pipeline operation/capability Finding Tier3Name: Pipeline temp/pressure/flow parameter(s) Finding Modifier Name: Design Finding Report Text: Pipeline - Pipeline operation/capability - Pipeline temp/pressure/flow parameter(s) - Design Finding Tier1Name: Pipeline Finding Tier2Name: Pipeline structure Finding Tier3Name: Pipe coatings/anti-corrosion Finding Modifier Name: Damaged/degraded Finding Report Text: Pipeline - Pipeline structure - Pipe coatings/anti-corrosion - Damaged/degraded Finding Tier1Name: Pipeline Finding Tier2Name: Pipeline structure Finding Tier3Name: Pipe Finding Modifier Name: Fatigue/wear/corrosion Finding Report Text: Pipeline - Pipeline structure - Pipe - Fatigue/wear/corrosion Finding Tier1Name: Personnel Finding Tier2Name: Experience/knowledge Finding Tier3Name: Training Finding Tier4Name: (general) Finding Modifier Name: SCADA operations personnel Finding Report Text: Personnel - Experience/knowledge - Training - SCADA operations personnel Finding Tier1Name: Pipeline Finding Tier2Name: Pipeline operation/capability Finding Tier3Name: Pipeline integrity/capacity Finding Modifier Name: Inadequate inspection Finding Report Text: Pipeline - Pipeline operation/capability - Pipeline integrity/capacity - Inadequate inspection Finding Tier1Name: Pipeline Finding Tier2Name: Pipeline structure Finding Tier3Name: Pipe Finding Modifier Name: Failure Finding Report Text: Pipeline - Pipeline structure - Pipe - Failure Official NTSB investigation data. NTSB findings determine probable cause and make safety recommendations; they do not adjudicate civil liability or regulatory violations. What Happened On 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. At 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. What We Found The 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. PIR-22-02 <<>> Issued: August 15, 2022 Pipeline Investigation Report: NTSB/PIR-22/02 Enbridge Inc. Natural Gas Transmission Pipeline Rupture and Fire Danville, Kentucky August 1, 2019 Abstract: This report discusses the August 1, 2019, rupture of an Enbridge Inc. 30-inch natural gas transmission pipeline in Danville, Kentucky, which released 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, as well as property damage in the surrounding area. Safety issues identified in this report include nonconservative assumptions used to calculate the potential impact radius, incomplete evaluation of the risks caused by a change of gas flow direction, limitations in data analysis related to in-line inspection tool usage, incomplete assessment of threats and threat interactions, and missed opportunities in training and requalification practices. Three recommendations are made to Enbridge Inc., and three recommendations are made to the Pipeline and Hazardous Materials Safety Administration. <<>> Pipeline Investigation Report NTSB/PIR-22/02 Contents Figures ................................................................................................................. iv Tables .................................................................................................................... v Abbreviations and Acronyms ............................................................................... vi Executive Summary ..............................................................................................vii What Happened.............................................................................................................. vii What We Found .............................................................................................................. vii What We Recommended ............................................................................................. viii 1. Factual Information .......................................................................................... 1 1.1 Accident Description ............................................................................................... 1 1.2 Emergency Response .............................................................................................. 2 1.2.1 Enbridge Response ...................................................................................... 2 1.2.2 Local Emergency Response ........................................................................ 3 1.3 Injuries and Damages from the Gas Fire ............................................................... 4 1.4 Enbridge Natural Gas Systems and Pipeline Specifications ............................... 5 1.4.1 Texas Eastern Transmission, LP, Line 15 .................................................... 5 1.4.2 Danville Compressor Station ...................................................................... 7 1.4.3 Gas Control Center....................................................................................... 7 1.5 Postaccident Pipeline Examination and Testing .................................................. 8 1.5.1 On-Site Visual Examinations ........................................................................ 8 1.5.2 Microscope Examination of the Fracture Origin .................................... 10 1.5.3 Microhardness Testing ............................................................................... 11 1.5.4 Microstructure ............................................................................................. 12 1.5.5 Other Examinations .................................................................................... 12 i <<>> Pipeline Investigation Report NTSB/PIR-22/02 1.6 Line 15 Incident History ......................................................................................... 13 1.6.1 2003 Rupture ............................................................................................... 13 1.6.2 2014 to 2017 Operational Modifications ................................................ 14 1.6.3 2019 Danville Compressor Station Emergency Shutdown ................... 15 1.7 Enbridge Procedures, Operations, and Maintenance ...................................... 16 1.7.1 Company Background ............................................................................... 16 1.7.2 Emergency Response Plan ........................................................................ 17 1.7.3 Cathodic Protection ................................................................................... 18 1.8 Integrity Management ........................................................................................... 21 1.8.1 High Consequence Area Identification ................................................... 23 1.8.2 Threat Identification and Interaction ........................................................ 24 1.8.3 Risk Assessment .......................................................................................... 26 1.8.4 Integrity Assessment .................................................................................. 26 1.8.5 Hard Spot In-Line Inspection Data Analysis ............................................ 28 1.8.6 Data Validation ............................................................................................ 29 1.8.7 Response and Repair ................................................................................. 30 1.8.8 Program Performance ................................................................................ 30 1.8.9 Recent Integrity Management Program Changes .................................. 31 1.9 Postaccident Actions ............................................................................................. 32 2. Analysis .......................................................................................................... 34 2.1 Introduction ............................................................................................................ 34 2.2 The Accident ........................................................................................................... 35 2.3 Calculation of the Potential Impact Radius ......................................................... 37 2.4 Management of Gas Flow Reversal ..................................................................... 39 ii <<>> Pipeline Investigation Report NTSB/PIR-22/02 2.5 In-Line Inspection Tool and Data Analyses ......................................................... 40 2.6 Threat Assessment and Interactions .................................................................... 42 2.7 Training and Requalification Practices ................................................................ 44 3. Conclusions .................................................................................................... 45 3.1 Findings .................................................................................................................... 45 3.2 Probable Cause ....................................................................................................... 46 4. Recommendations ......................................................................................... 47 4.1 New Recommendations ......................................................................................... 47 Appendix A: Investigation .................................................................................. 49 Appendix B: Consolidated Recommendation Information ................................ 50 References ........................................................................................................... 53 iii <<>> Pipeline Investigation Report NTSB/PIR-22/02 Figures Figure 1. Aerial view of the Indian Camp Subdivision overlaid on Google Earth image. .................................................................................................................................................. 1 Figure 2. Process flow diagram for pipeline isolation. ...................................................... 2 Figure 3. Homes of decedent and rescued couple, rupture location, and gas flame direction. .................................................................................................................................. 5 Figure 4. Crater and ground bedding at rupture site. ....................................................... 9 Figure 5. Ejected pipeline segment. .................................................................................. 10 Figure 6. East face of the fracture origin. ........................................................................... 11 Figure 7. Map of Texas Eastern Transmission pipelines. (Courtesy Enbridge.) ........... 17 Figure 8. Map of the right of way for Lines 10, 15, and 25. ............................................. 19 Figure 9. Voltage outputs at Goodnight and Harris Creek rectifiers. ............................ 20 Figure 10. Integrity management process flow. ............................................................... 22 Figure 11. Human-occupancy buildings within the potential impact radius. (Courtesy of Enbridge.) ......................................................................................................................... 24 iv <<>> Pipeline Investigation Report NTSB/PIR-22/02 Tables Table 1. Enbridge emergency response actions ................................................................ 3 Table 2. Local emergency response actions ....................................................................... 4 Table 3. Recent ownership history for Texas Eastern Transmission ................................. 6 Table 4. Pipeline specifications of Line 15 at the rupture origin ...................................... 7 Table 5. External metal loss anomalies identified in ILI runs........................................... 21 Table 6. Integrity assessments performed on the ruptured pipeline segment between 2003 and 2019 ...................................................................................................................... 27 v <<>> Pipeline Investigation Report NTSB/PIR-22/02 Abbreviations and Acronyms API American Petroleum Institute CFR Co de of Federal Regulations CS compressor station DEGT Duke Energy Gas Transmission HCA high consequence area HSMFL hard spot magnetic flux leakage ILI in-line inspection IM integrity management L15 VS4 assessment segment “Line 15 Valve Section 4” LCFPD Lincoln County Fire Protection District MAOP maximum allowable operating pressure NTSB National Transportation Safety Board PHMSA Pipeline and Hazardous Materials Safety Administration PIR potential impact radius P-PIC Process Performance Improvement Consultants, LLC psig pounds per square inch, gauge SCADA Supervisory Control and Data Acquisition STD Standard TET Texas Eastern Transmission, LP vi <<>> Pipeline Investigation Report NTSB/PIR-22/02 Executive Summary What Happened On August 1, 2019, at 1:23 a.m. local time, an Enbridge Inc. (Enbridge) 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. At 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. What We Found We found that 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 resulted in hydrogen-induced cracking at the outer surface of the pipeline and its subsequent failure. We also found that the Pipeline and Hazardous Materials Safety Administration’s (PHMSA’s) equation for determining the potential impact radius of a pipeline rupture is based on assumptions that are inconsistent with findings from recent natural gas ruptures and human response data; thus, high consequence areas determined using the equation do not include the full area at risk. Enbridge and Spectra Energy Partners LP did not effectively identify, investigate or manage the impact of a 2014 gas flow reversal project for the level of hydrogen evolution, or generation, in the pipeline surface, which ultimately contributed to the failure of the pipeline. The extent of hard spots on pipelines evaluated using the hard spot magnetic flux leakage in-line inspection tool is likely unknown because of the limitations of the tool and analysis techniques found during this investigation. Further, insufficient data were available to support Enbridge’s classification of the threat of hard spots in the accident pipeline as inactive. Enbridge underestimated the risk posed by hard spots because its processes and procedures were inconsistent with PHMSA guidance and industry knowledge of hard spot threat interactions. Enbridge also missed an opportunity to address a lack of knowledge displayed by the Danville compressor station operator in an emergency shutdown earlier in vii <<>> Pipeline Investigation Report NTSB/PIR-22/02 2019; addressing this may have reduced the delay in the operator’s response at the station on the morning of the accident. We determined that the probable cause of the August 1, 2019, Enbridge 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. What We Recommended As a result of this investigation, we made a recommendation to PHMSA to revise the regulations regarding potential impact radius methodology based on data from recent natural gas pipeline ruptures and human response considerations. We also recommended that PHMSA advise natural gas transmission operators on the circumstances of this accident, the need to evaluate the risks associated with flow reversal projects, the impacts of such projects on hydrogen-induced cracking, the possible data limitations associated with the use of in-line inspection tools and analysis used in hard spot management programs, and the need to follow industry best practices when conducting in-line inspection data analysis. We made recommendations to Enbridge to evaluate the effectiveness of its corrosion control equipment and infrastructure following a major change in operations, like a gas flow reversal; modify its integrity management program to better address threats and threat interactions; and require disqualification, remedial training, and/or requalification of covered tasks whenever an employee does not follow procedures when responding to an emergency shutdown, rupture, or other abnormal operation. viii <<>> Pipeline Investigation Report NTSB/PIR-22/02 1. Factual Information 1.1 Accident Description On August 1, 2019, at 1:23 a.m. local time, a 30-inch-diameter natural gas transmission pipeline, Line 15, owned and operated by Enbridge Inc. (Enbridge), ruptured near Danville, Kentucky.1 As a result of the rupture, 1 person was fatally injured, 6 people were hospitalized, and over 75 residents were evacuated from the Indian Camp Subdivision, a residential community. The rupture released about 101.5 million cubic feet of natural gas and ejected a 33.2-foot-long section of pipeline that landed about 481 feet southwest of the rupture site. The releasing gas ignited and burned. Five residences in the subdivision were destroyed by fires, and an additional 14 were damaged. (See figure 1.) A nearby railroad track owned and operated by the Norfolk Southern Corporation sustained fire damage. Figure 1. Aerial view of the Indian Camp Subdivision overlaid on Google Earth image. Enbridge personnel completed isolation of the affected pipeline segment at 2:19 a.m., while a Lincoln County Sheriff’s Office deputy sheriff and the Lincoln 1 (a) Visit ntsb.gov to find additional information in the public docket for this NTSB accident investigation (case number PLD19FR002). Use the CAROL Query to search safety recommendations and investigations. (b) The ruptured pipeline was one of three parallel pipelines traversing the area. The pipelines will be discussed in more detail in section 1.4.1. (c) All times in this report are local time. 1 <<>> Pipeline Investigation Report NTSB/PIR-22/02 County Fire Protection District worked to rescue and evacuate residents and minimize the spread of the fire. The grass fires in the surrounding area were extinguished at 3:20 a.m., and the structure fires were extinguished at 4:13 a.m. 1.2 Emergency Response 1.2.1 Enbridge Response An Enbridge employee received a call at 1:23 a.m. about the event from a friend who lived near the rupture site. Enbridge’s gas control center received an informational pressure rate-of-change alarm on the discharge (south) side of the Danville compressor station (CS) on Line 15 at 1:24 a.m. 2 This alarm indicated a pressure drop in the pipeline of about 105 pounds per square inch (psi) in 1 minute. At 1:25 a.m. the Enbridge gas control center received a second pressure rate-of-change alarm. To isolate the affected pipeline segment, Enbridge personnel needed to close valves manually at the Danville CS (valve 15-393) and at a valve station located near Highway 49 (valve 15-382). (See figure 2). Figure 2. Process flow diagram for pipeline isolation. At 1:28 a.m., the Enbridge’s area supervisor received a call at home about the rupture from the employee first notified at 1:23 a.m. The supervisor directed that employee to the Highway 49 valve station to close valve 15-382. Then the area supervisor called the station operator at the Danville CS at 1:35 a.m. and instructed him to close valve 15-393 to isolate the damaged pipeline segment on the north side of the rupture. Although an on-duty station operator was present, saw a visible fire 2 Compressor stations increase the pressure of gas in a pipeline by compressing it. The discharge side of a compressor station is the higher-pressure output side. The suction side of a compressor station is the lower-pressure input side. The Danville CS was the closest compressor station to the rupture site, located 4.1 miles to the north. 2 <<>> Pipeline Investigation Report NTSB/PIR-22/02 from the station, and saw a low-pressure alarm at the CS, he did not act to close the manual valve at the CS until instructed by the area supervisor. The station operator manually closed valve 15-393 at 1:39 a.m., isolating the affected pipeline segment on the north side of the rupture. The Enbridge employee sent to manually close valve 15-382 arrived at the Highway 49 valve station at 2:13 a.m. and confirmed valve 15-382 was the correct valve to close by checking Enbridge’s Stanford Area Emergency Response Manual (2015), which was in his company vehicle. The employee closed valve 15-382, completing isolation of the ruptured segment at 2:19 a.m. The total time from the rupture to isolation was 56 minutes. Table 1 provides a detailed timeline of Enbridge’s emergency response actions. Table 1. Enbridge emergency response actions Time Activity 1:23 a.m. Enbridge employee receives notification of rupture from friend 1:24 a.m. First alarm received in Enbridge gas control center 1:25 a.m. Second alarm received in Enbridge gas control center 1:26 a.m. Enbridge gas control center attempts to contact Danville station operator 1:27 a.m. Enbridge gas control center receives report of accident from the public 1:28 a.m. Enbridge area supervisor dispatches employee to Highway 49 valve station 1:29 a.m. Danville station operator notifies Enbridge gas control center of fireball 1:30 a.m. Enbridge gas control center shuts off compressors at an upstream compressor station 1:30 a.m. Enbridge area supervisor notifies gas control center of valve closures required for isolation 1:35 a.m. Enbridge area supervisor instructs Danville station operator to close valve 15-393 1:39 a.m. Danville station operator manually closes valve 15-393 2:13 a.m. Enbridge employee arrives at Highway 49 valve station 2:19 a.m. Enbridge employee manually closes valve 15-382 at Highway 49 valve station, completing isolation 1.2.2 Local Emergency Response At 1:23 a.m., Bluegrass 911 Central Communications Center (Bluegrass 911) received a call from a motorist traveling by the accident site, who reported an explosion and massive fire.3 Shortly after, Bluegrass 911 requested emergency response to the accident site. At 1:35 a.m., an engine and a rescue/brush truck were dispatched from Fire Station 3 of the Lincoln County Fire Protection District (LCFPD), the closest station. Additionally, mutual aid was provided by several adjacent emergency services jurisdictions, including the Stanford Fire Department, Boyle County Fire Department, and Danville Police Department. The entire emergency response totaled 81 firefighters, 10 engines and 21 trucks. All structure fires were 3 Bluegrass 911 received 71 additional reports of the accident from the public after this initial call. 3 <<>> Pipeline Investigation Report NTSB/PIR-22/02 extinguished by 4:13 a.m. Table 2 provides a detailed timeline of local emergency response actions. Table 2. Local emergency response actions Time Activity 1:23 a.m. Initial report to Bluegrass 911 1:26 a.m. Bluegrass 911 requests response to the accident site 1:35 a.m. Engine and truck dispatched from LCFPD Fire Station 3 1:37 a.m. LCFPD arrives at accident site 1:39 a.m. LCFPD Assistant Chief assumes incident commander role 1:40 a.m. Command post established at Indian Camp Road and Route 127 2:19 a.m. Ruptured pipeline segment isolated 2:56 a.m. Suppression of grass fires begins 3:00 a.m. House-to-house searches performed by LCFPD, no individuals found 3:20 a.m. Surrounding grass fires extinguished 3:29 a.m. LCFPD checks area for natural gas with gas detectors, none observed 3:57 a.m. Suppression of structure fires begins 4:13 a.m. Structure fires extinguished A part-time, off-duty Lincoln County Sheriff’s Office deputy sheriff also responded to the accident site. While approaching the source of the natural gas fire, the deputy observed a man lying on the front porch of a burning residence about 480 feet from the rupture site. The deputy placed the injured man and the man’s wife, who he rescued from just inside the door to the house, in the police cruiser. In a postaccident interview with the National Transportation Safety Board (NTSB), the deputy described the heat in the area of the accident as “more than I [could] handle.“ The deputy also attempted to render aid to a woman lying on the ground nearby but determined she was deceased and, due to the intense heat, was unable to recover her. The deputy left the area with the two evacuees and transferred them to nearby ambulance personnel. 1.3 Injuries and Damages from the Gas Fire After rescuing the two injured individuals, the deputy sheriff drove to a local medical trauma center to have a minor burn injury treated. Three other residents of the subdivision were also transported to the facility for treatment. All five of the injured residents and the deputy sheriff were subsequently released after receiving medical care. The home of the deceased was located about 310 feet south of the rupture location. The deceased individual was about 640 feet south of the natural gas fire when she was found by the deputy sheriff. 4 <<>> Pipeline Investigation Report NTSB/PIR-22/02 Five residences were destroyed by resulting structure fires. Fourteen other residences suffered property damage to various degrees; some were 1,100 feet from the rupture crater. The gas flame direction, as shown by the darkened area of soil indicated with a black arrow in figure 3, was oriented along a true bearing of about 80°, or just north of due east. This flame direction was consistent with the direction of the pipeline at the rupture location. Figure 3. Homes of decedent and rescued couple, rupture location, and gas flame direction. 1.4 Enbridge Natural Gas Systems and Pipeline Specifications 1.4.1 Texas Eastern Transmission, LP, Line 15 The Enbridge asset involved in this accident, Texas Eastern Transmission LP (TET), a natural gas transmission pipeline system, connects the Gulf Coast with the northeastern United States. TET is a wholly owned subsidiary of Spectra Energy Partners LP (Spectra), which was purchased by Enbridge in 2017. Table 3 lists the recent ownership history for TET. 5 <<>> Pipeline Investigation Report NTSB/PIR-22/02 Table 3. Recent ownership history for Texas Eastern Transmission Owner of TET Time Period Texas Eastern Corporation January 30, 1947 – June 28, 1989 Panhandle Eastern Corporation June 29, 1989 – July 28, 1994 Panhandle Eastern Corporation/PanEnergy Corp July 29, 1994 – April 15, 2001 Duke Energy Gas Transmission Corporation April 16, 2001 – January 1, 2007 Spectra Energy Corp January 2, 2007 – October 31, 2013 Spectra Energy Partners, Limited Partnership November 1, 2013 – present Enbridge Inc. February 27, 2017 – present At the accident location, three parallel Enbridge pipelines (lines) transport natural gas through a common right-of-way: Line 10, Line 15, and Line 25. The rupture on TET Line 15 occurred at milepost 423.4.4 The impacted TET section was known as Tompkinsville to Danville and was located within the Stanford Area. The Danville CS is located at milepost 408.5 and the Highway 49 valve station was located at milepost 427.5. At the time of the rupture, gas in Line 15 was flowing south from the Danville CS to the Tompkinsville CS at 925 pounds per square inch, gauge (psig), which was less than the maximum allowable operating pressure (MAOP) of 936 psig.5 According to Enbridge, the pressure on Line 15 between the Tompkinsville CS and the Danville CS did not exceed the MAOP in the 5 years before the accident. The external protective coating type for Line 15 in the area of the rupture was coal tar enamel.6 Other pipeline specifications for Line 15 are shown in table 4. 4 A milepost is a unit of measure used to define the location on a pipeline relative to a chosen starting point in miles and fractions of miles. 5 Title 49 Code of Federal Regulations ( CFR ) Part 192.619, Maximum allowable operating pressure: Steel or plastic pipelines, specifies how the maximum allowable operating pressure is determined. 6 Coal tar enamel , also called coal tar wrap, was a coating commonly used in the 1950s. Hot tar formulated from coal tar pitches and inert fillers was applied to the pipeline exterior over a primer. Often, it was then covered with a fiberglass mesh and a felt wrap. Much of this original coating is still present on transmission pipelines across the United States, including on Line 15. 6 <<>> Pipeline Investigation Report NTSB/PIR-22/02 Table 4. Pipeline specifications of Line 15 at the rupture origin Pipeline Specification Value Diameter 30-inch Material Carbon Steel Grade/Specified Minimum Yield Strength1 X-52/52,000 psi Long Seam Weld Electric Flash-Welded Manufacturer A. O. Smith Corporation Year Manufactured 1957 Year Constructed 1958 Wall Thickness 0.375 inches Flow Direction (at time of rupture) South Class Location2 2 MAOP, south flow 936 psig Operating Pressure (at time of rupture) 925 psig CS Discharge Temperature (at time of rupture) 115ºF Soil Type Shale Cathodic Protection Method Impressed Current 1 American Petroleum Institute 5LX defines specific grades of carbon steel pipeline, each with a minimum yield strength. The higher the grade of the pipeline, the higher the strength of the steel used to manufacture that pipeline. 2 Title 49 Code of Federal Regulations 192.5 defines class locations, with four class locations representing different population levels present near a pipeline. Class 4 areas have the highest populations around them and present the highest risk, while Class 1 areas present the lowest relative risk. 1.4.2 Danville Compressor Station The Danville CS was the closest compressor station to the rupture site, located 4.1 miles to the north. The Danville CS is manned 24 hours a day, 365 days a year, by a station operator working a 12-hour shift. The station operator is supervised by an area supervisor.7 Station operators perform physical walkthroughs of the station, evaluate Supervisory Control and Data Acquisition (SCADA) information at a computer, and respond to various types of emergencies, including emergency shutdowns or valve isolations of the system.8 1.4.3 Gas Control Center Enbridge’s gas control center for its natural gas transmission pipelines is in Houston, Texas, and is the central location for monitoring and control of pipeline 7 The area supervisor oversees the Stanford Area segment of pipe and manages 15 employees, including 4 station operators. 8 Supervisory Control and Data Acquisition (SCADA) is a computer system for gathering and analyzing real-time data. SCADA systems are used in the pipeline industry to monitor and control pipeline systems. Station operators control and monitor a large amount of data and systems at the station. There are almost 2,500 distinct SCADA inputs at the Danville CS. 7 <<>> Pipeline Investigation Report NTSB/PIR-22/02 operations. The gas control center is staffed 24 hours a day, 365 days a year, by six gas controllers working in 12-hour shifts and supervised by personnel within the gas control center. Gas controllers monitor operating conditions, such as line pressure, flow rate, temperature, and gas composition. Depending on the data source, gas controllers can look at data on an instantaneous, per minute, or hourly basis. Gas controllers have authority to take immediate action in the event of an emergency, including a pipeline rupture. They notify the public and emergency response agencies when a potential accident is reported through their central phone line. The gas control center also coordinates information to and from the field during an emergency response, keeping track of which personnel are responding, where they are, and what actions they are taking. Gas controllers are also able to operate valves equipped for remote closure from the gas control center. Most valves on Line 15 require manual operation, including valves 15-382 and 15-393 on either side of the rupture. 1.5 Postaccident Pipeline Examination and Testing 1.5.1 On-Site Visual Examinations A crater was located in the area of the rupture; the crater and ground bedding under the pipe consisted of soil and broken pieces of shale. (See figure 4.) 8 <<>> Pipeline Investigation Report NTSB/PIR-22/02 Figure 4. Crater and ground bedding at rupture site. The NTSB’s on-scene examination of the ejected pipeline segment revealed that most of the external coal tar coating was consumed by fire, leaving large regions of the external pipe surface bare. The fracture face of the ejected segment exhibited chevron fracture features, helping investigators locate the origin of the fracture. 9 Figure 5 shows the origin of the fracture as indicated by the brackets; the arrows indicate the general direction of fracture propagation. 9 C hevron features , also known as a river pattern, is a fractographic pattern of marks that look like nested letters “V” or herringbone. The points of the chevrons can be traced back to the fracture origin. 9 <<>> Pipeline Investigation Report NTSB/PIR-22/02 Figure 5. Ejected pipeline segment. While on-site, the NTSB cut the ejected pipe section into three pieces to facilitate shipping and handling. The exposed fractured ends of the pipe, located within the rupture crater, were cut at the border of the crater. The pipe sections were crated and shipped to the NTSB Materials Laboratory for testing. 1.5.2 Microscope Examination of the Fracture Origin The NTSB Materials Laboratory examination of the fracture faces from the ejected pipe revealed that the fracture originated at the outer surface, as indicated in figure 6. The origin of the fracture and an area extending below it contained a flat region with a rough texture, shown enclosed by a yellow line. Fracture propagation was in the general direction indicated by the arrows. 10 The origin of the fracture showed no evidence of a gouge or dent and did not originate from a weld. The length of the origin at the outer surface measured about 0.8 inches, and shear lips extended from both ends.11 The fracture face at the inner surface (opposite the 10 Details of the fracture examination can be found in the NTSB Materials Laboratory Factual Report No. 19 -064 , February 6, 2020, in the docket for this accident. 11 A shear lip is a precise 45° lip of metal around the perimeter of a ductile overstress fracture area. 10 <<>> Pipeline Investigation Report NTSB/PIR-22/02 fracture origin) contained a minor shear lip, indicating the fracture did not start at the inner surface of the pipe. The fracture areas located outside of the north and south ends of the flat region were on a slant plane and contained a chevron pattern, consistent with overstress separation. Figure 6. East face of the fracture origin. A detailed scanning electron microscope examination of the fracture face revealed that the origin exhibited intergranular fracture features, which came from localized embrittlement caused by exposure to hydrogen. 12 The amount of intergranular fracture features decreased toward the inner surface of the pipe. 1.5.3 Microhardness Testing Two metallurgical cross sections, one longitudinal and one circumferential, were mad - **truncated:** true - **body characters:** 141065