{"operation":"document","citation":"DCA09FP007","title":"Pipeline rupture and gas release","source_type":"incident","agency":"National Transportation Safety Board","status":"current","official":true,"published_on":"2026-01-30","effective_on":"2009-05-04","summary":"Accident. in Palm City, FL, USA. on 2009-05-04. Florida Gas Transmission Company. Rupture","machine_formats":{"json":"https://regulus.evalyn.ai/document/ntsb-case-dca09fp007.json","markdown":"https://regulus.evalyn.ai/document/ntsb-case-dca09fp007.md"},"app_url":"https://regulus.evalyn.ai/document/ntsb-case-dca09fp007","source_url":"https://www.ntsb.gov/investigations/Pages/DCA09FP007.aspx","body":"NTSB investigation DCA09FP007.\n\nEvent Type: Accident\n\nEvent Date: 2009-05-04\n\nEvent City: Palm City\n\nEvent State Or Region: FL\n\nEvent Country: USA\n\nPipeline Operator: Florida Gas Transmission Company\n\nPipeline Type: Gas Transmission - Regulated\n\nAccident Type: Rupture\n\nCompletion Status: Completed\n\nReport Number: PAB-13-01\n\nProbable cause: The National Transportation Safety Board determines that the probable cause of the accident was environmentally assisted cracking under a disbonded polyethylene coating that remained undetected by the integrity management program. Contributing to the accident was Florida Gas Transmission Company’s failure to include the pipe section that ruptured in the integrity management program. Contributing to the prolonged gas release was the pipeline controller’s inability to detect the rupture because of SCADA system limitations and the configuration of the pipeline\n\nTier1Name: System operating\n\nTier2Name: Product leak/release\n\nTier1Name: System operating\n\nTier2Name: Pipe structural malfunction/failure\n\nFinding Tier1Name: Pipeline\n\nFinding Tier2Name: Pipeline operation/capability\n\nFinding Tier3Name: (general)\n\nFinding Modifier Name: Incorrect service/maintenance\n\nFinding Report Text: Pipeline - Pipeline operation/capability - (general) - Incorrect service/maintenance\n\nFinding Tier1Name: Pipeline\n\nFinding Tier2Name: Pipeline operation/capability\n\nFinding Tier3Name: (general)\n\nFinding Modifier Name: Inadequate inspection\n\nFinding Report Text: Pipeline - Pipeline operation/capability - (general) - Inadequate inspection\n\nFinding Tier1Name: Personnel\n\nFinding Tier2Name: Experience/knowledge\n\nFinding Tier3Name: (general)\n\nFinding Modifier Name: SCADA operations personnel\n\nFinding Report Text: Personnel - Experience/knowledge - (general) - SCADA operations personnel\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 coatings/anti-corrosion\n\nFinding Modifier Name: Failure\n\nFinding Report Text: Pipeline - Pipeline structure - Pipe coatings/anti-corrosion - 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 Monday, May 4, 2009, about 5:10 a.m. eastern daylight time, Florida Gas Transmission Company’s (FGT) line 100, an 18-inch-diameter natural gas transmission pipeline, ruptured about 6 miles south of Palm City, Florida. The rupture occurred in a sparsely populated rural area of Martin County and displaced about 106 feet of buried pipe onto the right-of-way between Interstate 95 (I-95) and the Florida Turnpike (SR-91). An estimated 36 million cubic feet of natural gas was released during the accident without ignition. Two parallel FGT natural gas transmission pipelines in the same right-of-way were undamaged. Three minor injuries were attributed to the rupture: two people were injured escaping from a vehicle that lost control and ran off the turnpike, and one member of the Palm Beach County Sheriff’s department walked through a dense cloud and inhaled natural gas. The rupture occurred between two automatic shutoff valves (ASV), but only one valve shut in response to the pressure drop on the pipeline.\nEmergency responders rerouted traffic on both SR-91 and I-95 and evacuated a high school and a residential subdivision that were nearby. The FGT control center did not receive any Supervisory Control and Data Acquisition (SCADA) alarms or recognize the rupture from SCADA data. However, emergency response personnel began notifying the FGT control center at 5:49 a.m., after which the control center dispatched three field operators to the scene. By 7:30 a.m., the field operators had stopped the flow of natural gas. Local authorities reopened I-95 by 8:00 a.m. and SR-91 by 11:15 a.m. About 2 hours 20 minutes had elapsed from the time of the rupture to the complete isolation of the flow of gas\n\nWhat We Found\nWe determined that the probable cause of the accident was environmentally assisted cracking under a disbonded polyethylene coating that remained undetected by the integrity management program.\nContributing to the accident was Florida Gas Transmission Company’s failure to include the pipe section that ruptured in the integrity management program. Contributing to the prolonged gas release was the pipeline controller’s inability to detect the rupture because of SCADA system limitations and the configuration of the pipeline.\n\nPAB-13-01\n<<<PAGE 1>>>\n\nL\nT\nR\nA\nN\nS\nP\nA\nO\nN\nR\nU\nR\nI\nB\nU\nS\nM\nT\nO\nI\nA\nT\nA\nU N U\nP\nL\nE\nT\nI\nO\nN\nN\nS\nA\nF\nE\nT\nB\nD\nO\nA\nR\nNational Transportation Safety Board\nWashington, D.C. 20594\nY\nPipeline Accident Brief\nAccident No.: DCA09FP007\nAccident Type: Rupture of Florida Gas Transmission Pipeline and Release of\nNatural Gas\nLocation: Near Palm City, Florida\nDate: May 4, 2009\nTime: 5:10 a.m. eastern daylight time\nOwner/Operator: Florida Gas Transmission Company\nFatalities: 0\nInjuries: 3\nDamage/Clean-up Cost: $606,360\nMaterial Released: Natural gas\nQuantity Released: 36 million standard cubic feet (estimated)\nPipeline Failure Pressure: 854 psig\nThe Accident\nOn Monday, May 4, 2009, about 5:10 a.m. eastern daylight time,\n1 Florida Gas\nTransmission Company’s (FGT)2 line 100, an 18-inch-diameter natural gas transmission\npipeline, ruptured about 6 miles south of Palm City, Florida. The rupture occurred in a sparsely\npopulated rural area of Martin County and displaced about 106 feet of buried pipe onto the\nright-of-way between Interstate 95 (I-95) and the Florida Turnpike (SR-91). An estimated\n36 million cubic feet of natural gas was released during the accident without ignition. Two\nparallel FGT natural gas transmission pipelines in the same right-of-way were undamaged.\n3\nThree minor injuries were attributed to the rupture: two people were injured escaping from a\nvehicle that lost control and ran off the turnpike, and one member of the Palm Beach County\nSheriff’s department walked through a dense cloud and inhaled natural gas. The rupture occurred\nbetween two automatic shutoff valves (ASV),\n4 but only one valve shut in response to the\npressure drop on the pipeline.\n1 All times in this report are eastern daylight time unless otherwise noted.\n2 From 2004 through 2006, FGT was owned by Citrus Corp. Cross Country Energy and El Paso Corporation\nindirectly owned 50 percent of Citrus Corp. In 2006, Southern Union Company purchased 50 percent interest in\nFGT from Cross Country Energy.\n3 FGT operates a 24-inch (line 200) and a 30-inch pipeline (line 300) in the same right-of-way as line 100.\n4 An automatic shutoff valve uses electric- or gas-powered actuators to operate the valve automatically based on\npipeline sensor readings. The sensor sends a signal to close the valve based on a preset rate of pressure decay in the\npipeline. An ASV does not require human interpretation of the pipeline operations, and it closes automatically based\non the established criteria.\nCORRECTED COPY NTSB/PAB-13/01\n\n<<<PAGE 2>>>\n\nEmergency responders rerouted traffic on both SR-91 and I-95 and evacuated a high\nschool and a residential subdivision that were nearby. The FGT control center did not receive any\nSupervisory Control and Data Acquisition (SCADA)5 alarms or recognize the rupture from\nSCADA data. However, emergency response personnel began notifying the FGT control center\nat 5:49 a.m., after which the control center dispatched three field operators to the scene. By\n7:30 a.m., the field operators had stopped the flow of natural gas. Local authorities reopened\nI-95 by 8:00 a.m. and SR-91 by 11:15 a.m. About 2 hours 20 minutes had elapsed from the time\nof the rupture to the complete isolation of the flow of gas.\nFGT operates more than 4,800 miles of Gulf Coast transmission lines from a control\ncenter in Houston, Texas. Lines start near Galveston Bay, Texas, and extend through Louisiana,\nMississippi, and Alabama before turning south along the Florida peninsula. At the time of the\naccident, the FGT system consisted of 25 compressor stations with a mainline capacity of\n2.25 billion cubic feet per day. The line 100 rupture occurred between compressor\nstation 20 (upstream) and station 21 (downstream). (See figure 1.)\nFigure 1. Route of Florida Gas Transmission’s three natural gas pipelines along Florida\npeninsula.\n5 FGT used a computer-based SCADA system to remotely monitor and control the movement of gas through its\npipelines. SCADA controllers at the SCADA center in Houston, Texas, monitored operating parameters such as\nflow rate, pressure, equipment status, and abnormal condition alarms.\nCORRECTED COPY 2 NTSB/PAB-13/01\n\n<<<PAGE 3>>>\n\nAccident Narrative\nA section of the ruptured 18-inch pipeline, about 106 feet long and weighing more than\n5,000 pounds, was ejected out of the ground and landed near the crater in two pieces,\n6 leaving\ntwo open ends of the pipe exposed and discharging natural gas. Within minutes, one of two\n18-inch ASVs closed, shutting off the gas flow to the upstream (north) end of the rupture and\nlimiting the discharging gas to the south end. (See figure 2.) FGT operated two parallel,\ninterconnected 24-inch and 30-inch natural gas transmission pipelines in the same right-of-way,\nbut the rupture of the 18-inch line did not damage the other two lines. After the rupture, the\nincreased flow of gas through the open pipe began to vent the stored gas volume in the\ninterconnected pipelines and reduce the pressure.\nFigure 2. Aerial photograph of ruptured 18-inch pipeline showing venting gas and dislodged\npipe near crater.\nAt the time of the accident, the 18-inch natural gas transmission line was operating at a\npressure of 854 pounds per square inch, gauge (psig), or 98.6 percent of the maximum allowable\noperating pressure (MAOP).7 The rupture occurred in the final hour of the Sunday evening shift\nat the FGT Houston control center, before the Monday morning shift change. The releasing gas\nfrom the rupture resulted in pressure drops on all three of the interconnected pipelines; however,\nno SCADA alarms were generated. The pipeline controller did not recognize the line pressure\nand gas volume reductions as being unusual for that time of day.\n6 The larger of the two pieces was about 104 feet long; the smaller piece was about 1.6 feet long.\n7 Title 49 Code of Federal Regulations (CFR) 192.3 defines maximum allowable operating pressure as the\nmaximum pressure at which a pipeline or segment of a pipeline may be operated. MAOP is established under\n49 CFR 192.619.\nCORRECTED COPY 3 NTSB/PAB-13/01\n\n<<<PAGE 4>>>\n\nEmergency Response\nThe initial call to the Florida Highway Patrol reporting the accident was made at\n5:16 a.m., about 6 minutes after the rupture. The first responders to the accident included the\nFlorida Highway Patrol and the Martin County Hazardous Materials Team, Fire Rescue\nDepartment, Police, and Sheriff’s Office. By 5:21 a.m., the Martin County Sheriff’s Office had\nreceived more than 31 calls reporting the incident. .\nAt 5:33 a.m., Martin County Fire Rescue workers were on scene near the rupture, and by\n5:49 a.m. Martin County Fire Rescue made the first notification to the FGT control center,\nerroneously reporting that a vehicle had struck an FGT pipeline. Within minutes of being\nnotified, an on-call field operator assigned to the Fort Pierce compressor station (station 20) and\nanother assigned to the West Palm Beach compressor station (station 21) were dispatched to the\nscene by the control center. Believing that the accident involved only an aboveground pipeline\nmarker rather than the buried pipeline, the control center staff remained unaware that a pipeline\nhad actually ruptured.\nBy 5:59 a.m., the on-scene emergency responders had confirmed that a natural gas\npipeline had ruptured. Emergency response personnel established a 1-mile perimeter around the\nsite because of the risk of ignition from a vehicle idling near the rupture. About this time, the\nMartin County Hazardous Materials Team notified the FGT control center that the accident\ninvolved a ruptured pipeline near the I-95 Stuart/Jupiter exit.\nAfter receiving the second call, the FGT gas controllers reviewed SCADA data and\nidentified drops in the pipeline pressures from station 20, drops in pressure at the Martin North\nFlorida Power and Light gas meter, and a noticeable drop in the stored gas volume in the\npipeline. At 6:05 a.m., another field operator was dispatched to the accident site. By 6:39 a.m.,\nabout 34 minutes after being dispatched, the first FGT field operator reported to the incident\ncommand near mile marker 129 and was able to see a white cloud and smell the gas. This field\noperator became the FGT incident commander.\nThe control center did not know which of the three lines had ruptured until a field\noperator on scene saw that the upstream 18-inch ASV was closed. At 7:09 a.m., an FGT field\noperator closed the remaining downstream ASV, and by 7:30 a.m. no discernible gas was flowing\nfrom the ruptured pipe. Emergency responders gradually cleared the roads of debris and restored\ntraffic to I-95 by 8:00 a.m. and to SR-91 by 11:15 a.m.\nInjuries and Evacuations\nAbout 6:40 a.m., the fire chief ordered the evacuation of South Fork High School and the\nFoxwood residential community, both less than a mile southwest of the rupture. The school\nremained closed for the day, and the fire chief staged additional units in Foxwood to respond to\nany fires that might break out if gas were to ignite. Emergency responders also closed I-95 and\nSR-91 in both directions to maintain about a 1-mile perimeter around the ruptured pipeline.\nThree injuries were directly attributed to the rupture and gas release. Two people\nsustained minor injuries while leaving their vehicle after the driver lost control and ran off the\nturnpike into the right-of-way. The third injury occurred when a member of the Palm Beach\nCORRECTED COPY 4 NTSB/PAB-13/01\n\n<<<PAGE 5>>>\n\nCounty Sheriff’s department walked through the dense natural gas cloud and inhaled natural gas\nwhile assisting with the response.\nPipeline Information\nHistory\nThe ruptured pipeline section8 consisted of four pipe segments buried to a depth of about\n3 feet 9 inches.9 Two of the 18-inch-diameter ruptured pipe segments were part of the original\n1959 installation with a spiral-wrapped, field-applied Polyken 900 general utility polyethylene\ntape as the primary means of corrosion protection. These two polyethylene-tape–coated pipe\nsegments were manufactured to the American Petroleum Institute (API) Standard 5LX10 grade\nX5211 with a 0.25-inch nominal wall thickness and a direct current electric resistance\nwelded (ERW) longitudinal weld seam. Samples from the pipe material were tested, and the\nresults showed that the mechanical and chemical properties of these pipe segments met the\nrequirements of the API standard.\nAfter the original installation of the pipe, a hydrostatic pressure test was performed to a\npressure of 1,085 psig, and an MAOP of 975 psig was assigned to the pipeline. In the latter half\nof 1971, line 100 was hydrostatically pressure tested again, to 1,320 psig, to qualify portions of\nthe pipeline for Class 3 operation. This resulted in an MAOP of 866 psig, which was in place at\nthe time of the accident.\n12\nThe NTSB Materials Laboratory examination revealed that the two remaining segments\nof the ruptured section, downstream of girth weld 3, had been replaced with pipe that was newer\nthan the original pipe segments. (See figure 3.) Each of the newer segments had an ERW\nlongitudinal weld seam and was coated with fusion bonded epoxy. The newer segment farthest\ndownstream had a thicker wall than the other three pipe segments of the ruptured section. The\nFGT integrity management group stated that the two newer segments13 were installed in late\n2004 because of corrosion features identified during a magnetic flux leakage (MFL) in-line\ninspection that same year. FGT could not provide records of the replacement project that\nidentified why the work was performed or whether an analysis of the defects was conducted on\n8 Herein, section applies to multiple segments of pipeline; segment refers to a single joint of pipe between an\nupstream and a downstream girth (circumferential) weld.\n9 Pipeline burial depth is measured from the ground surface to the top of the pipe.\n10 The API develops industry-based consensus standards that support oil and gas production and distribution.\nAPI 5LX is a specification for line pipe.\n11 Grade X52 signifies that the pipe has a specified minimum yield strength (SMYS) of 52,000 psi. Yield\nstrength is a measure of the pipe’s material strength and indicates the stress level at which the material will exhibit\npermanent deformation. Although yield strength is expressed in psi, this value is not equivalent to a pipe’s internal\npressure.\n12 Title 49 CFR 192.611 defines the requirements for a change in class location. Class 3 MAOP was 60 percent\nof the pressure at the SMYS. The SMYS pressure was 1,444 psig for the ruptured pipe.\n13 According to FGT, three 18-inch-diameter segments were installed on line 100 in December 2004: 18.3 feet\nof 0.25-inch wall thickness API 5L grade X60 ERW, 41.7 feet of 0.375-inch wall thickness API 5L grade X52\nseamless, and 39.6 feet of 0.375-inch wall thickness API 5L grade X65 ERW.\nCORRECTED COPY 5 NTSB/PAB-13/01\n\n<<<PAGE 6>>>\n\nthe replaced pipe segments. No other maintenance or excavation activities were identified near\nthe ruptured segment. In addition to the tape coating, line 100 had a cathodic protection system.14\nFigure 3. Side view of crater and four pipe segments of ruptured section.\nInvestigators examined SCADA pressure data from the upstream compressor station for\nthe preceding year to identify the maximum operating pressure and operating ranges. The highest\nrecorded pressure during this period was 865.4 psig, and the average operating pressure was\nabout 850 psig. The largest daily low to high pressure range was 214 psig, with an average range\nof 36.7 psig.\nNatural gas operators are required by 49 CFR Part 191 to report incidents involving leaks\non transmission pipelines to the Pipeline and Hazardous Materials Safety Administration\n(PHMSA). Two FGT incident reports15 identified failures caused by stress corrosion cracking\n(SCC)16 on polyethylene-tape–coated pipelines in Florida and Alabama that were installed about\n1959.\n14 Cathodic protection is a corrosion mitigation method used by the pipeline industry to protect underground\nsteel structures. The system uses direct current power supplies at selected locations along the pipeline to supply\nprotective electrical current. The protective current is supplied to the pipeline through a ground bed that typically\ncontains a string of suitable anodes, with soil as an electrolyte. A wire connected to the pipeline provides the return\npath for the current to complete the circuit.\n15 PHMSA report numbers 19850184 (November 19, 1984) and 19850185 (February 25, 1985).\n16 Stress corrosion cracking is a form of environmentally assisted cracking produced under the combined action\nof corrosion and tensile stress typically manifesting as clusters of small cracks in the external body of the pipe.\nCORRECTED COPY 6 NTSB/PAB-13/01\n\n<<<PAGE 7>>>\n\nPipeline Configuration\nLine 100 was one of three parallel, interconnected, or looped, pipelines operating along a\n56.8-mile right-of-way. It transported natural gas north to south between compressor stations\n20 and 21. (See figure 4.) The ruptured section was about 27.7 miles downstream of station 20.\nBranch connections from all three transmission lines delivered gas to many commercial and\nmunicipal customers between stations, including a Florida Power and Light power plant (Martin\nNorth). According to statements made by the pipeline controllers, it was normal to see a drop in\npipeline pressure in the mornings and evenings when energy demand peaked. The 30-inch\npipeline primarily operated as a loop, supplementing gas to the 18-inch and 24-inch transmission\nlines at the Jupiter regulating station through 12-inch-diameter cross-connections. Dual\npressure-reducing regulators protected the lower MAOP on the 18-inch line from the higher\nMAOP on the 30-inch line.17\nFigure 4. Simplified schematic of 18-inch, 24-inch, and 30-inch interconnected transmission\nlines between compressor stations 20 and 21.\nASV Line Break Actuators\nThe rupture occurred between ASV 20-1 and ASV 20-2 on the 18-inch main line.\nASV 20-1 was about 8 miles upstream of the rupture site, and ASV 20-2 was about 12 miles\ndownstream. ASV 20-2 was less than 3 miles from the 12-inch cross-connect joining the 30-inch\nand 18-inch pipelines. Both the 18-inch main line ASV and the 12-inch cross-connect ASV\nincluded line break actuators that automatically close the valves if a rupture or large leak occurs.\n17 The 18-inch pipeline was rated for a MAOP of 866 psig, and the 24- and 30-inch pipelines were both rated at\na MAOP of 975 psig.\nCORRECTED COPY 7 NTSB/PAB-13/01\n\n<<<PAGE 8>>>\n\nThe line break actuators are designed to close the valve when the rate of pressure drop in the\npipeline exceeds a predefined set point.\n18 FGT stated that all of the line break actuators were\nidentical in operation, including set points. The line break actuator on ASV 20-2 was set to trip at\na pressure drop of 15.5 psig against an operating line pressure of 800 psig.\nAfter the rupture, the upstream flow was stopped when the line break actuator at\nASV 20-1 tripped and closed the valve about 2 minutes after the rupture, whereas the line break\nactuator downstream of the rupture at ASV 20-2 did not trip. ASV 20-2 was closed by hand by an\nFGT crew about 2 hours after the rupture. After the accident, FGT tested the line break actuator\nat ASV 20-2, and it tripped as intended at its design set point.\nThe FGT operations group performed yearly inspections and testing of the line break\nactuators to verify they operated properly. The manufacturer’s service manual defines the\nrelationship between rate of pressure drop and line pressure. If the rate of pressure drop is not\nsteep enough, then the line break actuator may not trip. The line break actuator on ASV 20-1 did\nnot trip when the line ruptured, most likely because the rate of pressure drop at the line break\nactuator was below the set point of the device. The limitations and design considerations for the\nuse of line break actuators, including when they are installed in looped systems, are documented\nin a 1995 Southwest Research Institute report, Remote and Automatic Main Line Valve\nTechnology Assessment:\n19\nBoth field experience and simulation results show that rate of pressure drop\nmeasurements in looped lines are not as reliable for line break detection as in\nsingle line systems. Because flow from adjacent loops feed the ruptured line\nthrough open crossovers, pressure in the ruptured line does not fall as fast as it\nwould if it were in a single line or if crossovers were closed.\nSCADA System\nWhen the pipeline ruptured, the SCADA pressure readings at the upstream compressor\nstation showed a 24.3 psig drop20 on the l8-inch line followed by steadily decreasing pressures in\nboth the 30-inch and the 24-inch transmission lines.21 The SCADA system reported the pressures\nat each compressor station and the stored volume of gas in the pipeline, but the system did not\nreport intermediate pressure or flow readings22 for the main line. None of the main line valves or\ncross-connect regulators included position feedback to SCADA. After the rupture, the controllers\n18 The line break actuator used pneumatic logic to compare the pressure in the pipeline to the pressure in a\nreserve cylinder. When the difference in pressure between the reserve cylinder and the pipeline meets a preset value,\nthe actuator (gas over hydraulics) closes the mainline valve. Once tripped, the line break actuator has to be reset\nmanually.\n19 C. R. Sparks et al., Remote and Automatic Main Line Valve Technology Assessment, Gas Research Institute\nReport No. GRI-95/0101 (Project No. 04-6609 for Gas Research Institute), (San Antonio: Southwest Research\nInstitute, 1995).\n20 SCADA pressure readings from compressor station 20 showed a pressure drop between 5:10 a.m. and\n5:12 a.m. from 853.8 psig to 829.5 psig.\n21 SCADA pressure readings at compressor station 20 showed a nearly identical pressure drop on the 24-inch\nand 30-inch pipelines from 899.7 psig to 813.8 psig between 5:17 a.m. and 7:07 a.m.\n22 Some branch connections to customer sites included pressure and flow readings that were viewable over\nSCADA and could be used by the control center to examine intermediate conditions.\nCORRECTED COPY 8 NTSB/PAB-13/01\n\n<<<PAGE 9>>>\n\ndid not know that ASV 20-1 had closed or that the cross-connect pressure regulators had fully\nopened.\nLine 100 normally operated with frequent flow and pressure changes based on the\ndemand for gas, and SCADA alarms were set to warn controllers about abnormal conditions.\nHowever, no SCADA alarms were triggered throughout this accident. The Monday morning shift\ncontroller stated that because SCADA showed no alarms, he did not examine the pressure drop\nor historical pressure trends until after the second call from emergency responders. The\ncontroller further stated that at the time of the accident, the drop in pressures on the three lines\nappeared to be consistent with peak demand and that, without an alarm, the pressure drop alone\nwas not sufficient to suggest a leak or line rupture. FGT had incorporated both low- and high-\npressure alarm settings and rate-of-change alarms set to detect abnormal operations that resulted\nfrom 20-psig pressure swings. Although none of the three pipeline pressures reached the low\nalarm threshold, the pressure change on the 18-inch line after the rupture was above the 20-psig\nthreshold of the rate-of-change alarm.\nA review of the SCADA rate-of-change alarm revealed that it did not trigger because of\nthe upstream ASV closure and the SCADA scan rate. The rate-of-change alarm was programmed\nto alert the controller when a 20-psig difference from the previous recorded pressure was present\nover two scans of the pressure sensor (about 8 minutes at this location).\n23 Pressure trend data\nfrom the accident indicate that the initial 24-psig drop at the upstream compressor station did not\ncontinue for two full scans of the SCADA system. When ASV 20-1 closed, the upstream pressure\nin the pipeline stabilized, resulting in a pressure difference less than 20 psig within the two scans,\nso the rate-of-change alarm did not activate.\nExamination of the Accident Pipe\nAbout 106 feet of pipe weighing about 5,000 pounds was ejected from the ground in two\npieces. The larger of the two pieces measured about 104 feet long and was found opened up and\nfolded over onto itself. (See figure 5.) The smaller piece measured 1.6 feet long and came to rest\nnear the larger piece.\n23 FGT stated that the scan rate or time for SCADA to receive updated data from the instrumentation was about\n4 minutes on this portion of the system.\nCORRECTED COPY 9 NTSB/PAB-13/01\n\n<<<PAGE 10>>>\n\nFigure 5. One hundred four-foot-long section of 18-inch buried pipe that was dislodged from the\nground.\nSample lengths of pipe were taken from each of the four segments of the ruptured\nsection, including portions of the intact ends (upstream and downstream), and sent to the NTSB\nMaterials Laboratory for testing and analysis. An examination of the fracture face showed that\nthe rupture originated between girth welds 1 and 2 and simultaneously traveled upstream and\ndownstream along the longitudinal seam welds through four girth welds. The fracture origin was\nabout 30.5 feet downstream of girth weld 1 and was oriented in the 4 o’clock position24\ncoinciding with the longitudinal seam weld. (See figure 3.)\nTape Coating, Corrosion, and Cracking\nExamination of the Polyken 900 (polyethylene) tape revealed deterioration of the\nadhesive bond with the pipe surface, with preexisting wrinkles and air pockets or bubbles along\nthe length of the ruptured section. Beneath the tape wrap, general corrosion and corrosion pitting\nwere observed on the exterior surface of the pipe. Corrosion pitting damage was observed near\nthe fracture and at regular 12-inch intervals where the overlapped spiral coating had disbonded\nfrom the pipe. The general and localized pitting corrosion indicated that the cathodic protection\nwas ineffective in mitigating corrosion damage. Pitting corrosion, as deep as 0.075 inches\n(30 percent of the nominal wall thickness), was observed on or near longitudinal seam weld. The\ndepth of the corrosion, measured at several locations near the origin, resulted in a remaining wall\nthickness that was less than the specified minimum. No internal corrosion was observed on the\nruptured pipe section.\nMagnetic particle inspections25 conducted on the outer surface of the pipe along and\nadjacent to the fracture revealed several colonies of longitudinal cracks. (See figure 6.) These\ncolonies of cracks were identified on both sides and close to the longitudinal seam weld.\n24 Orientation is given as the clockwise position when looking down the pipe in the direction of flow (north to\nsouth). The 12 o’clock position represents the top of the pipe.\n25 Magnetic particle inspection is a nondestructive test method for detecting the existence and extent of linear\nindications (such as cracks) open to the surface of ferromagnetic materials.\nCORRECTED COPY 10 NTSB/PAB-13/01\n\n<<<PAGE 11>>>\n\nAdditional colonies of cracks were found on the segment of pipe upstream from the rupture\norigin.\nFigure 6. Longitudinal cracks and corrosion pits observed below longitudinal weld seam and\nupstream of rupture origin.\nFurther examination of the cracks revealed that they initiated from the bottom of\ncorrosion pits on the external pipe surface. (See figure 7.) The initial stages of crack\nadvancement into the pipe wall showed characteristics consistent with environmentally assisted\nmechanisms such as near-neutral pH stress corrosion cracking (NNpHSCC)26 or corrosion\nfatigue.27 Final stages of crack propagation in the pipe wall exhibited little secondary branching\nand was most consistent with NNpHSCC. NNpHSCC and corrosion fatigue are both forms of\nenvironmentally assisted cracking that share many similar metallurgical characteristics.\nAccording to the Canadian Energy Pipeline Association’s Stress Corrosion Cracking,\nRecommended Practices, SCC occurs in pipelines with mechanically failed coatings in the\nabsence of adequate cathodic protection.\n28 The same publication indicated that pipe wrapped\nwith polyethylene tape has the greatest susceptibility to SCC compared to all other coatings. The\nproblem created by disbonded polyethylene coating and cathodic protection shielding is well\nknown in the pipeline industry.29\n26 Near-neutral pH SCC is a specific form of environmentally assisted cracking that propagates through the\nmetal grain boundaries with little secondary branching. It was first noted on the polyethylene-tape–coated pipeline\nin the TransCanada Pipelines system in the 1980s.\n27 Corrosion fatigue is a form of environmentally assisted cracking in materials under the combined actions of\ncyclic loading and a corrosive environment.\n28 Stress Corrosion Cracking, Recommended Practices, 2nd ed., (Calgary, Alberta: Canadian Energy Pipeline\nAssociation, 2007).\n29 Disbondment of the tape coating from the outer pipe wall can result in moisture ingress between the tape and\nthe steel, promoting corrosion. In this instance, the polyethylene tape no longer separates the pipe wall from a\ncorrosive environment and the high electrical resistance of the tape shields the surface from receiving the adequate\nprotective current of the cathodic protection system.\nCORRECTED COPY 11 NTSB/PAB-13/01\n\n<<<PAGE 12>>>\n\nFigure 7. (Left) Cross section of colony of six longitudinal cracks (shown in figure 6) identified\nby arrows. (Right) magnified view of single crack (about 0.03 inches deep) advancing from\ncorrosion pit.\nThe Fracture Origin\nFracture features on the face of the rupture identified the origin area, which measured\nabout 6 inches long and was on the longitudinal weld seam. The longitudinal weld seam\nmeasured 0.255 inches thick in this region. The fracture face along the origin coincided with a\ndark colored region of corroded steel that extended from the outer surface of the pipe to a\nmaximum depth of about 75 percent of the longitudinal seam weld thickness. (See figure 8.) No\ncrack arrest features were observed on the fracture face. Two corrosion pits, about 1 inch apart,\nwere on the outer surface in the corroded region of the fracture origin. Both corrosion pits\nmeasured about 0.2 inches in diameter and extended 0.04 inches into the pipe wall. Closer\nexamination of the fracture surface near the two corrosion pits revealed radial marks emanating\nfrom the surface of the corroded region toward the inner wall. The corrosion pit at the deepest\nportion of the fracture origin included a subsurface crack that extended from the base of the pit.\nThe fracture emanated from corrosion pits on the outer pipe wall and propagated toward the\ninner wall to a depth of 75 percent of the weld seam thickness before the remaining pipe wall\nfailed from overstress.\nThe NTSB Materials Laboratory determined that the fracture most likely resulted from\nexternal environmentally assisted cracks along the longitudinal seam weld. The radial markings\non the fracture face show that these cracks emanated from corrosion pits. The darker corroded\nregion suggests that the crack propagation occurred over a long period before reaching a size that\nresulted in the rupture.\nCORRECTED COPY 12 NTSB/PAB-13/01\n\n<<<PAGE 13>>>\n\nFigure 8. Scanning electron microscope photograph of a portion of the fracture origin showing\ncorrosion pit at outer wall and subsurface crack.\nIntegrity Management\nIn January 2004, PHMSA issued the gas integrity management rule that established how\npipeline operators should identify, prioritize, assess, evaluate, repair, and validate the integrity of\ngas transmission pipelines using multiple assessment methods. This integrity management\napproach was directed at protecting high consequence areas (HCA) from catastrophic effects of\nruptured natural gas lines. The integrity management rule required that a pipeline operator\ncomplete a baseline assessment of 50 percent of HCA pipeline mileage by December 17, 2007,\nand of 100 percent by December 17, 2012. As part of the integrity management program, an\noperator must identify and evaluate all potential threats to HCA segments, collect and integrate\nrelevant data from the entire pipeline, and conduct a risk assessment in accordance with\nASME B31.8S.30\nClass Location\nTo determine which pipeline segments were covered under the integrity management\nrule, FGT used method 2, defined by 49 CFR 192.903,\n31 to calculate a potential impact radius\n30 ASME B31.8S-2004, “Managing System Integrity of Gas Pipelines;” ASME Code for Pressure Piping, B31\nsupplement to ASME B31.8.\n31 “The area within a potential impact circle containing (i) 20 or more buildings intended for human occupancy,\nunless the exception in paragraph (4) applies; or (ii) an identified site.”\nCORRECTED COPY 13 NTSB/PAB-13/01\n\n<<<PAGE 14>>>\n\nand identify HCA sites within that radius. FGT reported more than 600 miles of HCA pipeline\nsegments and 1,138 HCA locations covered under the integrity management program.\nThe ruptured section was defined by the integrity management group as being in a\nClass 1 location with no HCA identified sites.\n32 Therefore, FGT did not include the pipeline\nsection under the integrity management program. However, because HCA segments were located\nupstream and downstream of the rupture location, the entire 56.8 miles between compressor\nstations was inspected with in-line tools, including the pipe segments that ruptured, as part of the\nintegrity management baseline assessment.\nAfter the accident, a review of the area was conducted through PHMSA to examine\nwhether a neighboring high school qualified as an HCA “identified site.” The findings from the\nreview concluded that the rupture location should have been designated as Class 3 and should\nhave included an HCA identified site because the potential impact radius (366 feet) intersected\nthree semi-open structures at the nearby high school.\n33 (See figure 9.)\nFigure 9. Rupture location shown relative to nearby high school that was determined to fall\nwithin 366-foot potential impact radius.\n32 The hydrostatic testing conducted in 1971 qualified line 100 for Class 3 operation; however, at the time of the\naccident, the ruptured section was operated as Class 1 by FGT.\n33 FGT did not reduce the mainline valve spacing from Class 1 to Class 3 to meet the requirements under\n49 CFR 192.179, citing a PHMSA final ruling in the matter of Viking Gas Transmission (1998; CPF 32102).\nBecause the class change did not require pipe replacement, no mainline valves were required.\nCORRECTED COPY 14 NTSB/PAB-13/01\n\n<<<PAGE 15>>>\n\nIntegrity Assessments\nThe FGT risk assessment program in place in 200434 used a total risk methodology\naddressing the nine threat categories described in ASME B31.8S and classified threats as either\ntime dependent, stable, or time independent. Time-dependent threats include external corrosion\nand SCC. The total risk was defined as the product of the likelihood of an event multiplied by the\nconsequence of that event. The likelihood of failure was derived using appendix A of\nASME B31.8S and an internally developed consequence algorithm. The program used a\nprescriptive method combined with subject matter expert input to arrive at the total risk value.\nThe FGT risk assessment procedure stated that the threat of SCC is managed by external\nsurface coating systems, balanced cathodic protection, minimizing cyclic loading, and operating\nbelow 60 percent specified minimum yield strength (SMYS) (if possible). The procedure noted\nthat in-line inspection tool effectiveness35 for detecting SCC had not been adequately\ndemonstrated for gas lines, but the procedure outlined other methods that could be used to assess\nsusceptibility to SCC, including soil characterization, magnetic particle inspection, pressure\ntesting, and leak and rupture history.\nThe FGT 2004 risk assessment spreadsheet showed that the pipeline segments upstream\nand downstream of the rupture location had very low risk scores for both the external corrosion\nand the SCC categories.36 According to the FGT corrosion engineer, polyethylene-tape–coated\npipe has the highest risk weighting for SCC, but pipeline segments along the Florida peninsula\nhad no prior history of SCC-related failures.\nWhen SCC was identified as a risk in the relative risk matrix, the FGT 2004 integrity\nassessment procedures discussed the use of both direct assessment and hydrostatic spike pressure\ntesting.\n37 FGT stated that hydrostatic spike testing was the approach used for SCC and that direct\nassessment was not part of the integrity program.\nAppendix A of the 2004 FGT integrity assessment procedure states that the use of spike\ntesting is the method of choice when confirmed “significant” SCC38 is present and a proven\nEMAT tool39 is not commercially available. Without a direct assessment program, the FGT\n34 FGT risk and integrity procedures were Cross Country Energy procedures from 2004 until 2006 when the\ncompany was sold to Southern Union Gas (Panhandle Eastern).\n35 The FGT integrity assessment procedure lists the electromagnetic acoustic transducer (EMAT) and the\ncircumferential magnetic flux leakage (MFL) in-line inspection tools as being capable of SCC detection, but each\nhas","truncated":true,"body_characters":47055}