{"operation":"document","citation":"PHMSA FIR, Tennessee Gas Pipeline Company, 2011-03-01","title":"Failure Report- Tennessee Gas Pipeline Company 3/1/11","source_type":"incident","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2017-01-11","effective_on":"2011-03-01","summary":"Tennessee Gas Pipeline Company; Gas Transmission; OH; failure 2011-03-01; apparent cause: Material Failure.","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-fir-failure-report-tennessee-gas-pipeline-company-3111.json","markdown":"https://regulus.evalyn.ai/document/phmsa-fir-failure-report-tennessee-gas-pipeline-company-3111.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-fir-failure-report-tennessee-gas-pipeline-company-3111","source_url":"https://www.phmsa.dot.gov/safety-reports/failure-report-tennessee-gas-pipeline-company-3111","body":"<<<PAGE 1>>>\n\nDOT U.S. Department of Transportation\nPHMSA Pipeline and Hazardous Materials Safety Administration\nOPS Office of Pipeline Safety\nCentral Region\nPrincipal Investigator Gery Bauman/Public Utilities Commission of Ohio (PUCO)\nSenior Accident Investigator Brian Pierzina/Karen Butler\nRegion Director David Barrett/Allan Beshore\nDate of Report 7/30/2015\nSubject Failure Investigation Report—Tennessee Gas Pipeline\nCompany—Material Failure—Girth Weld\nOperator, Location, & Consequences\nDate of Failure 3/1/2011\nCommodity Released Natural Gas\nCity/County & State Cumberland/Guernsey, OH\nOpID & Operator Name 19160 Tennessee Gas Pipeline Company\nUnit # & Unit Name 9413 DIVISION E [IA]\nSMART Activity # 133678\nMilepost/Location Line 200-1/209-1 + 2258\nType of Failure Rupture, Material Failure, Girth Weld\nFatalities 0\nInjuries 0\nDescription of area impacted Class 1, Rural area, Non-HCA\nTotal Costs $ 389,949\n\n<<<PAGE 2>>>\n\nFailure Investigation Report—Tennessee Gas Pipeline Company\nMaterial Failure, Girth Weld\nFailure Date 3/1/2011\nExecutive Summary\nOn March 1, 2011, at approximately 7:15 a.m. EST,\n1 Tennessee Gas Pipeline Company (TGP) personnel\ndetected a natural gas release on the 26-inch diameter 200-1 pipeline downstream of the 209\nCompressor Station in Guernsey County, near Cumberland, Ohio. The employees heard a hissing sound\ndownstream (northeast) of the compressor station when they reported to work in the morning. After\ninvestigating, they confirmed a release coming from the 200-1 pipeline approximately 2,250 feet\ndownstream of the compressor station. Immediate measures were taken to shut down and isolate the\npipeline, including closing main line block valves (MLBVs) upstream and downstream from the release\nlocation.\nThe failure occurred in a wooded area near a pasture (Class 1 location, Rural, Non-HCA) approximately\n1,200 feet from the nearest residence, and was discovered to be the result of a ruptured girth weld. The\nfailed weld was removed—along with the adjacent welds upstream and downstream from the failure\nlocation—and sent to an independent metallurgical laboratory for analysis. The metallurgical analysis\ndetermined the failure was the result of a crack around the top portion of the girth weld dating back to\n1950, the year of the original construction. The crack was what is referred to as an underbead crack,\ncold crack, or hydrogen-assisted crack. It was approximately 31 inches long circumferentially, centered\nfrom the 10:00 o’clock to 2:40 o’clock position on the pipe. Stresses associated with pipe bend, possible\nground movement, and/or operational changes may have contributed to the eventual failure of the\nweld. When the first cut was made to remove the failed pipe the pipe ends shifted, indicating the\npresence of residual stresses on the pipeline. Additional cracks were identified outside of the failed\nportion of the girth weld, and the adjacent girth weld upstream from the failure had a similar crack that\nwas determined to date to original construction, but was not leaking.\nBased upon information provided by the TGP, it appears the failure occurred at 3:42 a.m. at a pressure\nof 709 pounds per square inch gage (psig). There were no injuries or evacuations associated with this\nincident, and the escaping gas did not ignite. The total reported costs associated with emergency\nresponse, pipe replacement, and site clean-up were $389,949.\nSystem Details\nThe TGP is an interstate natural gas transmission pipeline operator with approximately 12,000 miles of\npipeline, including 876 miles in Ohio. The TGP system in Ohio consists of four essentially parallel\npipelines that travel across the Ohio River near Portsmouth, Ohio, in a northeasterly direction, ending\nnear Boardman, Ohio. The four pipelines generally, but not always, share a common right-of-way. The\nfailure occurred on the Line 200-1 pipeline, a 26-inch diameter, 0.281-inch wall thickness, API 5LX Grade\nX-52, electric flash-welded (EFW) pipe manufactured by A.O. Smith. The pipeline was coated with coal\ntar enamel and asbestos wrap, and cathodically protected with impressed current. This pipeline was\nconstructed in 1950 with a maximum allowable operating pressure (MAOP) of 790 psig. The pipeline\nsection containing the girth weld was hydrostatically pressure tested without failure on September 27,\n1969, and was in a no-flow condition at the time the leak was discovered due to ongoing downstream\npipeline repairs being performed on Line Section 214-1. When the pipeline was constructed in 1950,\npipeline girth welds were not typically nondestructively tested. In 2004, the TGP ran a high-resolution\nMagnetic Flux Leakage (MFL) and Caliper In-line inspection (ILI). The ILI data was examined for\n1 All times are Eastern Standard Time (EST) unless otherwise noted.\nPage 2 of 6\n\n<<<PAGE 3>>>\n\nFailure Investigation Report—Tennessee Gas Pipeline Company\nMaterial Failure, Girth Weld\nFailure Date 3/1/2011\nindications of dents and metal loss, but was not subjected to an analysis that considered girth weld\ndefects.\nEvents Leading up to the Failure\nOn February 10, 2011, at approximately 10:30 p.m., the TGP experienced a pipeline rupture (girth weld\nfailure) on the Line 214-4 pipeline near Hanoverton, Ohio. Station 209 was operating when this failure\noccurred, but was taken offline as a result of the rupture and subsequent fire approximately 15 minutes\nlater. As the emergency response to the Hanoverton incident progressed, TGP Incident Command\ndetermined it would be necessary to bring Station 209 back online to maintain service to customers.\nThe request to bring Station 209 back online (for Lines 1, 2, and 3) was made at at 10:56 p.m. It was\nunknown at that time that the auto-close valves for all four pipelines at Valve Station 215 had closed\ndue to the rupture and fire. When Station 209 was brought back online, the gas discharge pressure rose\nrapidly from 740 psig to 765 psig between 12:18 a.m. and 12:23 a.m., then dropping to 743 psig by\n12:28 a.m. From that point on discharge pressure rose gradually, reaching a maximum recorded\npressure of 782 psig at 1:24 a.m., when Incident Command requested Station 209 be shut down. When\nit was determined that all four auto-close valves at Valve Station 215 had closed, and the TGP system\nisolated at that location, alternative means of providing service to distribution customers was\nestablished. This allowed Station 209 to remain offline until after the necessary repairs at 215-1 were\ncompleted; those repairs were still in process when the March 1, 2011, incident occurred. There were\nno reported maintenance activities on the section of pipe just downstream of Compressor Station 209 in\nthe area of the leak prior to March 1, 2011.\nEmergency Response\nThe leak was initially discovered by TGP employees when they reported for work at Compressor Station\n209 after they investigated a sound of escaping gas that could be heard from the station. Only two of\nthe four pipelines in the area of the failure share a common right-of-way, so the employees were quickly\nable to determine the release was coming from Line 1. The employees then began the process of\nisolating the pipeline, closing MLBV 209-1 (upstream from the failure) at Compressor Station 209 at 8:00\na.m. and MLBV 210-1 (downstream from the failure) at 8:20 a.m. This isolated approximately 12 miles\nof Line 1, including the failure location. The pressure on Line 1 was then monitored for a period of time,\nwith a pressure drop from 658 psig to 464 psig observed from 8:23 a.m. to 9:20 a.m. After receiving this\nadditional confirmation that Line 1 was leaking, the TGP employees prepared to blowdown the section\nof Line 1 between MLBV 209-1 and MLBV 210-1. The blowdown process began at 10:47 a.m. and was\ncompleted by 12:30 p.m. There was no fire or explosion associated with the incident. The TGP notified\nthe National Response Center (NRC) at 10:12 a.m. (NRC Report #968824), reporting that “a 26-inch steel\npipeline appears to have a leak due to unknown causes.” Both the Public Utilities Commission of Ohio\n(PUCO) and the Pipeline and Hazardous Materials Safety Administration (PHMSA) Central Region\nInspectors were dispatched to investigate. The PUCO inspector was in the area inspecting a different\npipeline operator, and arrived on-site at 11:25 a.m. The inspectors were able to provide field\nobservations, gather background information, and monitor investigation and repair activities.\nExcavation of the failure location did not begin until the morning of March 2, 2011.\nSummary of Return-to-Service\nPHMSA issued a Notice of Proposed Safety Order (NOPSO) to the TGP (CPF No. 3-2011-1001S) on March\n11, 2011, addressing both the failure on February 10, 2011, at Line 214-4, and the failure on March 1,\n2011, at 209-1. The NOPSO provisions required a written restart plan, 20% pressure reduction, airborne\ninstrumented leak survey, accelerated patrol surveillance activities, 3rd\n-party mechanical and\nPage 3 of 6\n\n<<<PAGE 4>>>\n\nFailure Investigation Report—Tennessee Gas Pipeline Company\nMaterial Failure, Girth Weld\nFailure Date 3/1/2011\nmetallurgical testing and failure analysis, historical ILI data re-analysis, performance of additional ILI,\nevaluation of the results for girth weld anomalies, analysis of Supervisory Control and Data Acquisition\n(SCADA) activities, root cause analysis, development and implementation of an integrity verification and\nremedial work plan, and monthly status reports. Good faith settlement discussions between the TGP\nand PHMSA culminated in a Consent Agreement that described the work to be performed to remediate\nthe integrity risks associated with the pipelines.\nOn March 22, 2011, the TGP replaced 86 feet of the Line 1 pipe with pre-tested pipe. Even though the\npipeline remained out of service, it was purged and loaded with natural gas to facilitate the required\nleakage survey from 209-1 to 210-1. Following the leakage survey, this section of Line 1 remained out of\nservice, isolated at a pressure of 475 psig. During May 2011, with PHMSA’s approval, the TGP\ntemporarily increased the pressure on Line 1 from 209-1 to 214-1 in order to facilitate the cleaning tool,\ngauge tool, and inspection tool runs required by the Consent Agreement. These activities were\ncompleted by May 12, 2011, after which the section between 209-1 and 210-1 was isolated once more\nand locked in at a pressure of 522 psig. Following investigation and remediation of anomalies reported\nby the prior and most recent ILI reviews, the TGP requested—and was granted—permission to return\nthe 209 to 210 section of Line 1 to service at full operating pressure. This was completed on October 28,\n2011.\nInvestigation Details\nAfter the area of the rupture was made safe, the rupture site was examined by employees of the TGP,\nPHMSA, and the Gas Pipeline Safety Section of PUCO. Records were requested regarding the history\nand operation of the pipeline, and the TGP hired Det Norske Veritas (DNV) to complete a metallurgical\ninvestigation of the failure. During the pipe removal process, the upstream and downstream welds\nwere radiographed and crack-like indications were observed in the upstream weld. As a result, the\nfailed girth weld and both the upstream and downstream welds were sent to the DNV for metallurgical\ninvestigation.\nPipe sections involving the three girth welds were removed and shipped to the DNV’s Columbus location\nfor a metallurgical investigation to determine the cause of the failure. The TGP expanded their root\ncause analysis (RCA) associated with the February 10, 2011, incident to include this girth weld failure.\nThe RCA team was comprised of subject matter experts from the TGP and outside contractors.\nAdditionally, soil scientists from Battelle Memorial Institute conducted a geologic and soil investigation\ninto the failure.\nThe results of the metallurgical analysis2 offered the following conclusions and discussion:\nThe results of the metallurgical analysis indicate that the leak initiated at a pre-existing crack in a\nfield girth weld. The crack was 2.6 feet long, circumferentially, and was located on the inside of\nthe pipe between the 10:00 and 2:40 o’clock orientations. The maximum depth of the crack was\n0.317 inches (79% through wall based on a pipe wall/girth weld thickness of 0.399 inches). The\npre-existing crack initiated at the toe of the root pass in the heat-affected zone of the weld. The\ncrack propagated primarily in the weld metal. The crack did alternate between the upstream\nand downstream root pass as it propagated. This type of crack is referred to as an under-bead\ncrack, cold crack, or hydrogen assisted crack. A discussion of the factors related to hydrogen-\nassisted cracking is given in Appendix B of the metallurgical report.\n2 DNV Final Report—Metallurgical Analysis of Girth Weld Leak on Tennessee Gas Pipeline’s 200-1 Line at Milepost\n209-1 + 0.44—May 20, 2011.\nPage 4 of 6\n\n<<<PAGE 5>>>\n\nFailure Investigation Report—Tennessee Gas Pipeline Company\nMaterial Failure, Girth Weld\nFailure Date 3/1/2011\nThe primary cause of the leak was the presence of the pre-existing weld crack. A contributing\nfactor in the failure was tensile axial stresses acting on the girth weld. The presence of the weld\ncrack near the top of the pipe suggests that bending stresses acted on the pipe to place the\ncrack in tension. This is consistent with shifting of the pipe after the initial field cut, in which the\nupstream end shifted upwards approximately 2.5 inches. Approximately 91 feet of the pipeline\nwas excavated (approximately 45.5 feet on both sides of the failed girth weld) at the time of the\ninitial cut.\nBelow is a summary of observations from the metallurgical analysis.\n The leak occurred at a field girth weld.\n A pre-existing weld crack was associated with the leak.\n The pre-existing crack was approximately 2.6 feet long, circumferentially, and\nlocated\n between the 10:00 and 2:40 o’clock orientations.\n The maximum depth of the crack was approximately 0.317 inches,\ncorresponding to 79% through wall based on a pipe wall/girth weld thickness of\n0.399 inches. The final brittle fracture was approximately 0.08 inches deep\ncorresponding to 21% of the pipe wall / girth weld thickness.\n The crack originated at the toe of the weld root pass and extended through the\nweld metal of the girth weld.\n Intergranular fractographic features were present in Regions 1 and 2 of the\ncrack.\nFindings and Contributing Factors\n1. There was a change in the operational history of the Cumberland Compressor Station\nimmediately upstream of the failed girth weld. The pipeline was shut-in due to the repair of the\ndownstream girth weld failure, and the ambient temperature at the time of failure was 24\ndegrees Fahrenheit. The cooler operating temperature of the pipeline could have increased\ntensile stresses due to thermal contraction of the pipe.\n2. Typically, pipelines are bent during construction to conform to local topography. The section of\npipe in the immediate vicinity of the girth weld contained a 7.9-degree sag bend; upon\nreplacement of the pipeline section, however, a sag bend of 5.5 degrees was installed to fit the\ntopography. The difference of 2.4 degrees between the original and replacement construction\nindicates the possibility of bending stresses acting across the weld.\n3. A geological analysis of the soil and the topography of the pipeline right-of-way in the vicinity of\nthe failed weld indicated soil creep perpendicular to the pipeline. This extremely slow ground\nmovement could increase the tensile stresses across the girth weld over time, leading to its\nfailure.\n4. The results of the DNV metallurgical investigation showed the failed girth weld contained a\npreexisting crack that extended through part of the girth weld. The preexisting crack initiated at\nthe toe of the root bead and penetrated through part of the weld. The crack was 2.6 feet long\ncircumferentially, and had a maximum depth of 0.317 inches (79% of the way through the wall\nbased on a total weld thickness of 0.399 inches). The laboratory classified the crack as a\nhydrogen crack, also known as an under-bead crack, cold crack, or hydrogen-assisted crack. The\nconculsion that it was a hydrogen crack that led to this failure is supported by the metallurgy of\nthe pipe and the welding electrodes used to complete the weld, as well as experience gained\nPage 5 of 6\n\n<<<PAGE 6>>>\n\nFailure Investigation Report—Tennessee Gas Pipeline Company\nMaterial Failure, Girth Weld\nFailure Date 3/1/2011\nregarding welding since the pipeline was built in 1950. No signs of fatigue were observed; the\ncrack formed during construction of the pipeline and remained dormant from the date of\nconstruction until the time of failure.\n5. The restart of Station 209 during the Line 214-4 incident on February 10-11, 2011, was initiated\nshortly after the incident. Fires were still burning at this time, and the status of Lines 1, 2, and 3\nwas unconfirmed. As a result of all four pipelines being isolated at Valve Station 215, the\ndischarge pressure at 209-1 reached at least 782 psig prior to the station being shut down again.\nThe pressure records provided by the TGP for the period following this event show that the\npressure at 209 was maintained between 630 psig and 670 psig until the end of February. The\npressure began to increase steadily on February 28th\n, rising from 670 psig to 709 psig, at which\npoint the failure occurred. It’s possible this pressure cycle, just 18 days before the failure, may\nhave been sufficient to destabilize the previously dormant defect.\nAppendices\nA Map and Photographs\nB NRC Report\nC Operator’s Report\nD Metallurgical Analysis\nE Root Cause Analysis (RCA)\nPage 6 of 6\n\n<<<PAGE 7>>>\n\nAppendix A - Map and Photographs\nMaterials Safety Administratior\nPipeline and Hazardou\nOPID 19160 Tennessee Gas Pipeline Co. - Cumberland, OH Incident\n:153\n1.5\n- Mies\nPHMSA CENTRAL REGION\nPage 1 of 5\n\n<<<PAGE 8>>>\n\nAppendix A - Map and Photographs\nPhoto 1 view of leak site looking south down the right-of-way. The compressor station can be seen in\nthe distance. The disturbed soil was blown from the ground as a result of the failed girth weld.\nPage 2 of 5\n\n<<<PAGE 9>>>\n\nAppendix A - Map and Photographs\nPhoto 2 shows the excavation around the failed girth weld.\nPage 3 of 5\n\n<<<PAGE 10>>>\n\nAppendix A - Map and Photographs\nPhoto 3 shows the failed girth weld.\nPage 4 of 5\n\n<<<PAGE 11>>>\n\nAppendix A - Map and Photographs\nPhoto 4 shows a close-up of the top of the failed girth weld.\nPage 5 of 5\n\n<<<PAGE 12>>>\n\nAppendix B - NRC Report\nPage 1 of 2\nNATIONAL RESPONSE CENTER 1-800-424-8802\n*** For Public Use ***\nInformation released to a third party shall comply with any\napplicable federal and/or state Freedom of Information and Privacy Laws\nIncident Report # 968824\nINCIDENT DESCRIPTION\n*Report taken at 10:12 on 01-MAR-11\nIncident Type: PIPELINE\nIncident Cause: UNKNOWN\nAffected Area:\nThe incident was discovered on 01-MAR-11 at 09:15 local time.\nAffected Medium: AIR INTO THE AIR\nSUSPECTED RESPONSIBLE PARTY\nOrganization: TENNESSEE GAS PIPELINE\nHOUSTON, TX 77046\nType of Organization: PRIVATE ENTERPRISE\nINCIDENT LOCATION\nSEE LAT/LONG County: GUERNSEY\nCOUNTY RD 15\nCLAYSVILLE RD\nCity: CLAYSVILLE State: OH Zip: 77046\nLatitude: 39 57' 12\" N\nLongitude: 081 40' 33\" W\n____________________________________________________________________________\nRELEASED MATERIAL(S)\nCHRIS Code: ONG Official Material Name: NATURAL GAS\nAlso Known As:\nQty Released: 0 UNKNOWN AMOUNT\nDESCRIPTION OF INCIDENT\nTHE CALLER IS REPORTING THAT A 26 INCH STEEL PIPELINE APPEARS TO HAVE A LEAK DUE TO\nUNKNOWN CAUSES. AN UNKNOWN AMOUNT OF NATURAL GAS WAS RELEASED TO THE ATMOSPHERE.\nINCIDENT DETAILS\nPipeline Type: TRANSMISSION\nDOT Regulated: YES\nPipeline Above/Below Ground: BELOW\nExposed or Under Water: NO\nPipeline Covered: UNKNOWN\nDAMAGES\nFire Involved: NO Fire Extinguished: UNKNOWN\nINJURIES: NO Hospitalized: Empl/Crew: Passenger:\nFATALITIES: NO Empl/Crew: Passenger: Occupant:\nEVACUATIONS: NO Who Evacuated: Radius/Area:\nDamages: NO\nLength of Direction of\nClosure Type Description of Closure Closure Closure\nAir: N\nRoad: N\nWaterway: N\nTrack: N\nPassengers Transferred: NO\nEnvironmental Impact: UNKNOWN\nMedia Interest: NONE Community Impact due to Material:\nMajor\nArtery:\nN\nREMEDIAL ACTIONS\nTHEY HAVE ISOLATED THE PIPELINE AND WILL DEPRESSURE IT.\nRelease Secured: NO\nhttp://www.nrc.uscg.mil/reports/rwservlet?standard_web+inc_seq=968824\n5/24/2013\nPage 1 of 2\n\n<<<PAGE 13>>>\n\nAppendix B - NRC Report\nPage 2 of 2\nRelease Rate:\nEstimated Release Duration:\nWEATHER\nWeather: PARTLY CLOUDY, 32ºF Wind speed: 2 MPH Wind directi\nADDITIONAL AGENCIES NOTIFIED\nFederal: NONE\nState/Local: OH PUC\nState/Local On Scene: NONE\nState Agency Number: NONE\nNOTIFICATIONS BY NRC\nATLANTIC STRIKE TEAM (MAIN OFFICE)\n01-MAR-11 10:19\nUSCG ICC (ICC ONI)\n01-MAR-11 10:19\nCGIS RAO ST. LOUIS (COMMAND CENTER)\n01-MAR-11 10:19\nDOT CRISIS MANAGEMENT CENTER (MAIN OFFICE)\n01-MAR-11 10:19\nU.S. EPA V (MAIN OFFICE)\n01-MAR-11 10:21\nNATIONAL INFRASTRUCTURE COORD CTR (MAIN OFFICE)\n01-MAR-11 10:19\nNOAA RPTS FOR OH (MAIN OFFICE)\n01-MAR-11 10:19\nOHIO DEPARTMENT OF HEALTH (OHDOH)\n01-MAR-11 10:19\nSECTOR OHIO VALLEY (COMMAND CENTER)\n01-MAR-11 10:19\nOH EPA ATTN: DUTY OFFICER (MAIN OFFICE)\n01-MAR-11 10:19\nOH EPA ATTN: DUTY OFFICER (SOUTHEAST DISTRICT OFFICE)\n01-MAR-11 10:19\nADDITIONAL INFORMATION\nNO ADDITIONAL INFORMATION.\n*** END INCIDENT REPORT # 968824 ***\nhttp://www.nrc.uscg.mil/reports/rwservlet?standard_web+inc_seq=968824\n5/24/2013\nPage 2 of 2\n\n<<<PAGE 14>>>\n\nAppendix C - Operator's Report\nNOTICE: This report is required by 49 CFR Part 191. Failure to report can result in a civil penalty not to\nexceed 100,000 for each viola ion for each day that such violation persists except that the maximum civil\npenalty shall not exceed $1,000,000 as provided in 49 USC 60122.\nOMB NO: 2137-0522\nEXPIRATION DATE: 10/31/2016\nOriginal Report\nDate: 03/28/2011\nU.S Department of Transportation\nPipeline and Hazardous Materials Safety Administration\nNo. 20110036 - 16819\n--------------------------------------------------\n(DOT Use Only)\nINCIDENT REPORT - GAS TRANSMISSION AND\nGATHERING PIPELINE SYSTEMS\nA federal agency may not conduct or sponsor, and a person is not required to respond to, nor shall a person be subject to a penalty for failure to comply\nwith a collection of information subject to the requirements of the Paperwork Reduction Act unless that collection of information displays a current valid\nOMB Control Number. The OMB Control Number for this information collection is 2137-0522. All responses to this collection of information are\nmandatory. Send comments regarding the burden estimate or any other aspect of his collection of information, including suggestions for reducing the\nburden to: Information Collection Clearance Officer, PHMSA, Office of Pipeline Safety (PHP-30) 1200 New Jersey Avenue, SE, Washington, D.C. 20590.\nINSTRUCTIONS\nImportant: Please read the separate instructions for completing this form before you begin. They clarify the information requested and provide specific\nexamples. If you do not have a copy of the instructions, you can obtain one from the PHMSA Pipeline Safety Community Web Page at\nhttp://www.phmsa.dot.gov/pipeline/library/forms.\nPART A - KEY REPORT INFORMATION\nReport Type: (select all that apply) Original: Supplemental: Yes Final:\nYes\nLast Revision Date: 07/20/2015\n1. Operator's OPS-issued Operator Identification Number (OPID): 19160\n2. Name of Operator TENNESSEE GAS PIPELINE COMPANY\n3. Address of Operator:\n3a. Street Address 1001 LOUISIANA ST SUITE 1000\n3b. City HOUSTON\n3c. State Texas\n3d. Zip Code: 77002\n4. Local time (24-hr clock) and date of the Incident: 03/01/2011 07:15\n5. Location of Incident:\nLatitude: 39.945198\nLongitude: -81.680369\n6. National Response Center Report Number (if applicable): 968824\n7. Local time (24-hr clock) and date of initial telephonic report to the\nNational Response Center (if applicable): 03/01/2011 10:12\n8. Incident resulted from: Unintentional release of gas\n9. Gas released: (select only one, based on predominant volume\nreleased) Natural Gas\n- Other Gas Released Name:\n10. Estimated volume of commodity released unintentionally - Thousand\nCubic Feet (MCF): 29,745.00\n11. Estimated volume of intentional and controlled release/blowdown -\nThousand Cubic Feet (MCF) 13,338.00\n12. Estimated volume of accompanying liquid release (Barrels):\n13. Were there fatalities? No\n- If Yes, specify the number in each category:\n13a. Operator employees\n13b. Contractor employees working for the Operator\n13c. Non-Operator emergency responders\n13d. Workers working on the right-of-way, but NOT\nassociated with this Operator\n13e. General public\n13f. Total fatalities (sum of above)\n14. Were there injuries requiring inpatient hospitalization? No\n- If Yes, specify the number in each category:\n14a. Operator employees\n14b. Contractor employees working for the Operator\n14c. Non-Operator emergency responders\n14d. Workers working on the right-of-way, but NOT\nassociated with this Operator\n14e. General public\n14f. Total injuries (sum of above)\n15. Was the pipeline/facility shut down due to the incident? Yes\n- If No, Explain:\nForm PHMSA F 7100.2 Page 1 of 13\nReproduction of this form is permitted\nPage 1 of 13\n\n<<<PAGE 15>>>\n\nAppendix C - Operator's Report\n- If Yes, complete Questions 15a and 15b: (use local time, 24-hr clock)\n15a. Local time and date of shutdown 03/01/2011 08:20\n15b. Local time pipeline/facility restarted 03/22/2011 16:09\n- Still shut down? (* Supplemental Report Required)\n16. Did the gas ignite? No\n17. Did the gas explode? No\n18. Number of general public evacuated: 0\n19. Time sequence (use local time, 24-hour clock):\n19a. Local time operator identified Incident– effective 10-2014,\nchanged from \"Incident\" to \"failure\" 03/01/2011 07:15\n19b. Local time operator resources arrived on site 03/01/2011 08:00\nPART B - ADDITIONAL LOCATION INFORMATION\n1. Was the origin of the Incident onshore? Yes\n- Yes (Complete Questions 2-12)\n- No (Complete Questions 13-15)\nIf Onshore:\n2. State: Ohio\n3. Zip Code: 43732\n4. City Cumberland\n5. County or Parish Guernsey\n6. Operator designated location Milepost/Valve Station\nSpecify: 209-1@2258\n7. Pipeline/Facility name: Line 200-1\n8. Segment name/ID: Valve Section 209-1\n9. Was Incident on Federal land, other than the Outer Continental Shelf\n(OCS)? No\n10. Location of Incident : Pipeline Right-of-way\n11. Area of Incident (as found) : Underground\nSpecify: Under soil\nOther – Descr be:\nDepth-of-Cover (in): 33\n12. Did Incident occur in a crossing? No\n- If Yes, specify type below:\n- If Bridge crossing –\nCased/ Uncased:\n- If Railroad crossing –\nCased/ Uncased/ Bored/drilled\n- If Road crossing –\nCased/ Uncased/ Bored/drilled\n- If Water crossing –\nCased/ Uncased\nName of body of water (If commonly known):\nApprox. water depth (ft) at the point of the Incident:\nSelect:\nIf Offshore:\n13. Approx. water depth (ft) at the point of the Incident:\n14. Origin of Incident:\n- If \"In State waters\":\n- State:\n- Area:\n- Block/Tract #:\n- Nearest County/Parish:\n- If \"On the Outer Continental Shelf (OCS)\":\n- Area:\n- Block #:\n15. Area of Incident:\nPART C - ADDITIONAL FACILITY INFORMATION\n1. Is the pipeline or facility: - Interstate - Intrastate Interstate\n2. Part of system involved in Incident: Onshore Pipeline, Including Valve Sites\n3. Item involved in Incident: Weld, including heat-affected zone\n- If Pipe – Specify:\n3a. Nominal diameter of pipe (in): 26\n3b. Wall thickness (in): .281\n3c. SMYS (Specified Minimum Yield Strength) of pipe (psi): 52,000\nForm PHMSA F 7100.2 Page 2 of 13\nReproduction of this form is permitted\nPage 2 of 13\n\n<<<PAGE 16>>>\n\nAppendix C - Operator's Report\n3d. Pipe specification: Exceeds API 5L\n3e. Pipe Seam – Specify: Flash Welded\n- If Other, Describe:\n3f. Pipe manufacturer: A.O. Smith\n3g. Year of manufacture: 1950\n3h. Pipeline coating type at point of Incident – Specify: Coal Tar\n- If Other, Describe:\n- If Weld, including heat-affected zone – Specify: Pipe Girth Weld\n- If Other, Describe:\n- If Valve – Specify:\n- If Mainline – Specify:\n- If Other, Describe:\n3i. Mainline valve manufacturer:\n3j. Year of manufacture:\n- If Other, Descr be:\n4. Year item involved in Incident was installed: 1950\n5. Material involved in Incident: Carbon Steel\n- If Material other than Carbon Steel or Plastic – Specify:\n6. Type of Incident involved: Rupture\n- If Mechanical Puncture – Specify Approx. size:\nin. (axial) by\nin. (circumferential)\n- If Leak - Select Type:\n- If Other – Describe:\n- If Rupture - Select Orientation: Circumferential\n- If Other – Descr be:\nApprox. size: in. (widest opening): .4\nby in. (length circumferentially or axially): 31.2\n- If Other – Describe:\nPART D - ADDITIONAL CONSEQUENCE INFORMATION\n1. Class Location of Incident: Class 1 Location\n2. Did this Incident occur in a High Consequence Area (HCA)? No\n- If Yes:\n2a. Specify the Method used to identify the HCA:\n3. What is the PIR (Potential Impact Radius) for the location of this\nIncident? Feet: 504\n4. Were any structures outside the PIR impacted or otherwise damaged\ndue to heat/fire resulting from the Incident? No\n5. Were any structures outside the PIR impacted or otherwise damaged\nNOT by heat/fire resulting from the Incident? No\n6. Were any of the fatalities or injuries reported for persons located\noutside the PIR? No\n7. Estimated Property Damage :\n7a. Estimated cost of public and non-Operator private\nproperty damage paid/reimbursed by the Operator – effective 6-\n2011, \"paid/reimbursed by the Operator\" removed\n$ 10,000\nEstimated cost of gas released unintentionally – effective 6-2011,\nmoved to item 7f\nEstimated cost of gas released during intentional and controlled\nblowdown – effective 6-2011, moved to item 7g\n7b. Estimated cost of Operator's property damage & repairs $ 200,825\n7c. Estimated cost of Operator's emergency response $ 6,800\n7d. Estimated other costs $ 0\nDescribe:\n7e. Property damage subtotal (sum of above) $ 217,625\nCost of Gas Released\n7f. Estimated cost of gas released unintentionally $ 118,980\n7g. Estimated cost of gas released during intentional and\ncontrolled blowdown $ 53,344\n7h. Total estimated cost of gas released (sum of 7.f & 7.g above) $ 172,324\nTotal of all costs $ 389,949\nForm PHMSA F 7100.2 Page 3 of 13\nReproduction of this form is permitted\nPage 3 of 13\n\n<<<PAGE 17>>>\n\nAppendix C - Operator's Report\nPART E - ADDITIONAL OPERATING INFORMATION\n1. Estimated pressure at the point and time of the Incident (psig): 709.00\n2. Maximum Allowable Operating Pressure (MAOP) at the point and\ntime of the Incident (psig): 790.00\nAdded 10-2014 2a. MAOP established by 49 CFR section: 192.619(a)(3)\n- If Other, specify:\n3. Descr be the pressure on the system or facility relating to the\nIncident: Pressure did not exceed MAOP\n4. Not including pressure reductions required by PHMSA regulations\n(such as for repairs and pipe movement), was the system or facility\nrelating to the Incident operating under an established pressure\nrestriction with pressure limits below those normally allowed by the\nMAOP?\nNo\n- If Yes - (Complete 4a and 4b below)\n4a. Did the pressure exceed this established pressure\nrestriction?\n4b. Was this pressure restriction mandated by PHMSA or the\nState?\n5. Was \"Onshore Pipeline, Including Valve Sites\" OR \"Offshore Pipeline,\nIncluding Riser and Riser Bend\" selected in PART C, Question 2? Yes\n- If Yes - (Complete 5a. – 5e. below):\n5a. Type of upstream valve used to initially isolate release source: Manual\n5b. Type of downstream valve used to initially isolate release\nsource:\nManual\n5c. Length of segment isolated between valves (ft): 63,307\n5d. Is the pipeline configured to accommodate internal inspection\ntools? Yes\n- If No – Which physical features limit tool accommodation? (select all that apply)\n- Changes in line pipe diameter\n- Presence of unsuitable mainline valves\n- Tight or mitered pipe bends\n- Other passage restrictions (i.e. unbarred tee's, projecting\ninstrumentation, etc.)\n- Extra thick pipe wall (applicable only for magnetic flux\nleakage internal inspection tools)\n- Other\n- If Other, Describe:\n5e. For this pipeline, are there operational factors which\nsignificantly complicate the execution of an internal inspection tool\nrun?\nNo\n- If Yes, which operational factors complicate execution? (select all that apply)\n- Excessive debris or scale, wax, or other wall build-up\n- Low operating pressure(s)\n- Low flow or absence of flow\n- Incompatible commodity\n- Other\n- If Other, Describe:\n5f. Function of pipeline system: Transmission System\n6. Was a Supervisory Control and Data Acquisition (SCADA)-based\nsystem in place on the pipeline or facility involved in the Incident? Yes\n- If Yes:\n6a. Was it operating at the time of the Incident? Yes\n6b. Was it fully functional at the time of the Incident? Yes\n6c. Did SCADA-based information (such as alarm(s), alert(s),\nevent(s), and/or volume or pack calculations) assist with the\ndetection of the Incident?\nNo\n6d. Did SCADA-based information (such as alarm(s), alert(s),\nevent(s), and/or volume calculations) assist with the confirmation of\nthe Incident?\nNo\n7. How was the Incident initially identified for the Operator? Local Operating Personnel, including contractors\n- If Other – Describe:\n7a. If \"Controller\", \"Local Operating Personnel, including\ncontractors\", \"Air Patrol\", or \"Ground Patrol by Operator or its\ncontractor\" is selected in Question 7, specify:\nOperator employee\n8. Was an investigation initiated into whether or not the controller(s) or\ncontrol room issues were the cause of or a contributing factor to the\nIncident?\nNo, the Operator did not find that an investigation of the\ncontroller(s) actions or control room issues was necessary\ndue to: (provide an explanation for why the Operator did not\ninvestigate)\nForm PHMSA F 7100.2 Page 4 of 13\nReproduction of this form is permitted\nPage 4 of 13\n\n<<<PAGE 18>>>\n\nAppendix C - Operator's Report\n- If No, the operator did not find that an investigation of the\ncontroller(s) actions or control room issues was necessary due to:\n(provide an explanation for why the operator did not investigate)\nPressures were never abnormal or in excess of MAOP.\n- If Yes, Describe investigation result(s) (select all that apply):\n- Investigation reviewed work schedule rotations, continuous\nhours of service (while working for the operator), and other\nfactors associated with fatigue\n- Investigation did NOT review work schedule rotations,\ncontinuous hours of service (while working for the Operator)\nand other factors associated with fatigue\n- Provide an explanation for why not:\n- Investigation identified no control room issues\n- Investigation identified no controller issues\n- Investigation identified incorrect controller action or\ncontroller error\n- Investigation identified that fatigue may have affected the\ncontroller(s) involved or impacted the involved controller(s)\nresponse\n- Investigation identified incorrect procedures\n- Investigation identified incorrect control room equipment\noperation\n- Investigation identified maintenance activities that affected\ncontrol room operations, procedures, and/or controller\nresponse\n- Investigation identified areas other than those above –\nDescribe:\nPART F - DRUG & ALCOHOL TESTING INFORMATION\n1. As a result of this Incident, were any Operator employees tested\nunder the post-accident drug and alcohol testing requirements of DOT's\nDrug & Alcohol Testing regulations?\nNo\n- If Yes:\n1a. How many were tested:\n1b. How many failed:\n2. As a result of this Incident, were any Operator contractor employees\ntested under the post-accident drug and alcohol testing requirements of\nDOT's Drug & Alcohol Testing regulations?\nNo\n- If Yes:\n2a. How many were tested:\n2b. How many failed:\nPART G - APPARENT CAUSE\nSelect only one box from PART G in the shaded column on the left representing the APPARENT Cause of the Incident, and answer the\nquestions on the right. Describe secondary, contributing, or root causes of the Incident in the narrative (PART H).\nApparent Cause: G5 - Material Failure of Pipe or Weld\nG1 - Corrosion Failure - only one sub-cause can be picked from shaded left-hand column\nCorrosion Failure – Sub-cause:\n- If External Corrosion:\n1. Results of visual examination:\n- If Other, Describe:\n2. Type of corrosion: (select all that apply)\n- Galvanic\n- Atmospheric\n- Stray Current\n- Microbiological\n- Selective Seam\n- Other\n- If Other – Describe:\n3. The type(s) of corrosion selected in Question 2 is based on the following: (select all that apply)\n- Field examination\n- Determined by metallurgical analysis\n- Other\n- If Other – Describe:\n4. Was the failed item buried under the ground?\nForm PHMSA F 7100.2 Page 5 of 13\nReproduction of this form is permitted\nPage 5 of 13\n\n<<<PAGE 19>>>\n\nAppendix C - Operator's Report\n- If Yes:\n4a. Was failed item considered to be under cathodic protection at\nthe time of the incident?\n- If Yes, Year protection started:\n4b. Was shielding, tenting, or disbonding of coating evident at the\npoint of the incident?\n4c. Has one or more Cathodic Protection Survey been conducted\nat the point of the incident?\nIf \"Yes, CP Annual Survey\" – Most recent year conducted:\nIf \"Yes, Close Interval Survey\" – Most recent year conducted:\nIf \"Yes, Other CP Survey\" – Most recent year conducted:\n- If No:\n4d. Was the failed item externally coated or painted?\n5. Was there observable damage to the coating or paint in the vicinity of\nthe corrosion?\n- If Internal Corrosion:\n6. Results of visual examination:\n- If Other, Describe:\n7. Cause of corrosion (select all that apply):\n- Corrosive Commodity\n- Water drop-out/Acid\n- Microbiological\n- Erosion\n- Other\n- If Other, Describe:\n8. The cause(s) of corrosion selected in Question 7 is based on the following (select all that apply):\n- Field examination\n- Determined by metallurgical analysis\n- Other\n- If Other, Describe:\n9. Location of corrosion (select all that apply):\n- Low point in pipe\n- Elbow\n- Drop-out\n- Other\n- If Other, Describe:\n10. Was the gas/fluid treated with corrosion inhibitors or biocides?\n11. Was the interior coated or lined with protective coating?\n12. Were cleaning/dewatering pigs (or other operations) routinely\nutilized?\n13. Were corrosion coupons routinely utilized?\nComplete the following if any Corrosion Failure sub-cause is selected AND the \"Item Involved in Incident\" (from PART C,\nQuestion 3) is Pipe or Weld.\n14. Has one or more internal inspection tool collected data at the point\nof the Incident?\n14a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run:\n- Magnetic Flux Leakage Tool\nMost recent year run:\n- Ultrasonic\nMost recent year run:\n- Geometry\nMost recent year run:\n- Caliper\nMost recent year run:\n- Crack\nMost recent year run:\n- Hard Spot\nMost recent year run:\n- Combination Tool\nMost recent year run:\n- Transverse Field/Triaxial\nMost recent year run:\n- Other\nMost recent year run:\nIf Other, Describe:\n15. Has one or more hydrotest or other pressure test been conducted\nsince original construction at the point of the Incident?\n- If Yes,\nForm PHMSA F 7100.2 Page 6 of 13\nReproduction of this form is permitted\nPage 6 of 13\n\n<<<PAGE 20>>>\n\nAppendix C - Operator's Report\nMost recent year tested:\nTest pressure (psig):\n16. Has one or more Direct Assessment been conducted on this\nsegment?\n- If Yes, and an investigative dig was conducted at the point of the Incident:\nMost recent year conducted:\n- If Yes, but the point of the Incident was not identified as a dig site:\nMost recent year conducted:\n17. Has one or more non-destructive examination been conducted at\nthe point of the Incident since January 1, 2002?\n17a. If Yes, for each examination conducted since January 1, 2002, select type of non-destructive examination and indicate most\nrecent year the examination was conducted:\n- Radiography\nMost recent year examined:\n- Guided Wave Ultrasonic\nMost recent year examined:\n- Handheld Ultrasonic Tool\nMost recent year examined:\n- Wet Magnetic Particle Test\nMost recent year examined:\n- Dry M","truncated":true,"body_characters":54967}