# Failure Report- Panhandle Eastern Pipeline Co 8/25/08 - **operation:** document - **citation:** PHMSA FIR, Panhandle Eastern Pipeline Co, 2008-08-25 - **title:** Failure Report- Panhandle Eastern Pipeline Co 8/25/08 - **source type:** incident - **agency:** Pipeline and Hazardous Materials Safety Administration - **status:** historical - **official:** true - **published on:** 2010-10-25 - **effective on:** 2008-08-25 - **summary:** Panhandle Eastern Pipeline Co; Gas Transmission; MO; failure 2008-08-25; apparent cause: Corrosion External. - **machine formats:** - **json:** https://regulus.evalyn.ai/document/phmsa-fir-failure-report-panhandle-eastern-pipeline-co-82508.json - **markdown:** https://regulus.evalyn.ai/document/phmsa-fir-failure-report-panhandle-eastern-pipeline-co-82508.md - **app url:** https://regulus.evalyn.ai/document/phmsa-fir-failure-report-panhandle-eastern-pipeline-co-82508 - **source url:** https://www.phmsa.dot.gov/safety-reports/failure-report-panhandle-eastern-pipeline-co-82508 **body:** <<>> Pipeline System: Houstonia 200 Line Pipeline Failure Investigation Report Operator: Panhandle Eastern Pipeline Company, LP Location: Mile Post 21.6 Medium Released: Natural gas Date of Occurrence: 8/25/2008 Quantity: 13,518,578 CF PHMSA Arrival Time & Date: 8/25/08 1:00 p.m. Total Damages $ 1,046,359 Investigation Responsibility: State PHMSA NTSB Other Company Reported Apparent Cause: Corrosion Excavation Natural Forces Incorrect Operation Other Outside Force Damage Material and/or Welds Equipment and Operations Other Rupture Yes No Leak Yes No Fire Yes No Explosion Yes No Evacuation Yes No Number of Persons Area Narrative Summary Short summary of the Incident/Accident which will give interested persons sufficient information to make them aware of the basic scenario and facts. Panhandle Eastern Pipeline Company (PEPL) experienced failure of the Houstonia 200 line near Mile Post 21.6. There were no evacuations, road closings, fires, injuries or fatalities as a result of the failure. The failure did not occur in a high consequence area (HCA). The failure occurred on August 25, 2008, at approximately 8:51 a.m. CDT. The failure is located on a rocky hillside in a rural area west of Pilot Grove, Missouri in Cooper County. The failure was identified by PEPL when Houston Gas Control detected a pressure drop in the Houstonia 200 Line. The failure was located at approximately 9:00 a.m. when a PEPL field technician reported gas blowing near Mile Post 21.6. PEPL isolated the segment at approximately 9:30 a.m., by manually closing mainline valves 2 Gate and 3 Gate. The distance between 2 Gate and 3 Gate is approximately 16 miles. The pipeline experienced a longitudinal rupture in the pipe body. The rupture created a 50 feet by 33 ft by 7 feet deep crater in the ground. Two pipeline segments totalling 28 feet in length and a coupling were ejected from the crater a distance up to 300 feet from the rupture site. The failure origin was a 16 inch long area of reduced wall thickness located at the 6:00 orientation. The portion of the pipeline containing the failure is comprised of 24-inch diameter by 0.281-inch wall thickness, API 5L-X48, manufactured by A.O. Smith and contains a longitudinal electric flash welded (EFW) seam. The reported maximum allowable operating pressure (MAOP) is 800 psig, which corresponds to 71% of the specified minimum yield strength (SMYS). The pressure at the time and location of failure was 795 psig, which corresponds to 70% of the SMYS (99% of MAOP). The MAOP was established in accordance with 192.619 ( c ), the highest actual operating pressure to which the segment was subjected during the five years preceding July 1, 1970. A hydrostatic test of the pipeline was performed in 1955. Details of the hydrostatic test are unknown. The pipeline, installed in 1937, is joined by circumferential girth welds and Dresser couplings. The pipeline external coating is coal tar. The pipeline has an impressed curent cathodic protection system that was reportedly energized in 1955. The findings of PEPL's investigation are as follows: 1) The failure occurred due to tensile overload at a region of wall thinning caused by external corrosion. 2) The maximum wall loss measured at the rupture surface was 0.21 inches depth (75% of wall thickness). - 1 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report PEPL submitted a return to service plan to PHMSA that included a temporary 20% pressure reduction and remediation of anomalies found in a high resoultion MFL tool run. They subsequently remediated 30 anomalies with RPR less than 1.15 and replaced 912 feet of pipe. On 12/19/2009 the temporary pressure restriction was removed. ACTIVITY #: 122653 OPERATOR ID #: 15105 UNIT ID #: 4093 NRC REPORT #: 881717 INCIDENT REPORT # (FORM 7100.2): 20090030 -- 5319 Region/State __Central _______________________ Reviewed by: __David Barrett __original initialed _______ Principal Investigator: _Roger Sneegas________ Title: __Director – Central Region___________________ Date: _10/12/2010 ________________________ Date: __10/13/2010 _________________________ - 2 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Failure Location & Response Location (City, Township, Range, County/Parish): Pilot Grove, Missouri (Acquire Map) Address or M.P. on Pipeline: 21.6 (1) Type of Area (Rural, City): Rural (1) Date: 8/25/2008 Time of Failure: 8:51 a.m. Time Detected: 9:00 a.m. Time Located: 9:10 a.m. How Located: A technician - Jerry Miller - heard the pipeline blowing from the nearest road at about 9:00 a.m. Gas control had previously noted a pressure drop at 8:51 a.m. NRC Report #: 881717 (Attach Report) Time Reported to NRC: 10:15 a.m. on 8/25/2008 Type of Pipeline: Reported by: Liz Rutherford Gas Distribution Gas Transmission Hazardous Liquid LNG LP Interstate Gas Interstate Liquid LNG Facility Municipal Intrastate Gas Intrastate Liquid Public Utility Jurisdictional Gas Gathering Offshore Liquid Master Meter Offshore Gas Jurisdictional Liquid Gathering Offshore Gas - High H2S CO2 Pipeline Configuration (Regulator Station, Pump Station, Pipeline, etc.): Mainline Houstonia 200 Operator/Owner Information Owner: Panhandle Eastern Pipeline Address: 5444 Westheimer Road Houston TX Company Official: Eric Amundsen Phone No.: 713-989-7460 Fax No.: Operator: Panhandle Eastern Pipeline Address: 5444 Westheimer Road Houston TX Company Official: Eric Amundsen Phone No. 713-989-7460 Fax No. Drug and Alcohol Testing Program Contacts Drug Program Contact & Phone: Brett Laaser Alcohol Program Contact & Phone: 713-989-7549 N/A Damages Product/Gas Loss or Spill(2) 13,518,578 CF Estimated Property Damage $ 25,000 Amount Recovered 0 Associated Damages(3) $ 628,063 1 Photo documentation 2 Initial volume lost or spilled 3 Including cleanup cost - 3 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Damages Estimated Amount $ 393,296 Description of Property Damage: The failure caused a crater in the right-of-way measuring about 50 X 33 feet and 7 feet deep. Two segments of pipe (46 feet total) were ejected from the crater. Customers out of Service: Yes No Number: Suppliers out of Service: Yes No Number: Fatalities and Injuries Fatalities: Yes No Company: Contractor: Public: Injuries - Hospitalization: Yes No Company: Contractor: Public: Injuries - Non-Hospitalization: Yes No Company: Contractor: Public: Total Injuries (including Non-Hospitalization): Company: Contractor: Public: Name Job Function Yrs w/ Comp. Yrs. Exp. Type of Injury Drug/Alcohol Testing N/A Were all employees that could have contributed to the incident, post-accident tested within the 2 hour time frame for alcohol or the 32 hour time frame for all other drugs? Yes No Results Job Function Test Date & Time Location Type of Drug Pos Neg Gas System Controller 8/25/2008 Houston TX - 4 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report System Description Describe the Operator's System: The Houstonia 200 line runs from Liberal KS to Howell MI. It is 24-inch diameter 0.281-inch wall X48 pipe installed in 1937. Pipe Failure Description N/A Length of Failure (inches, feet, miles): 46 feet (1) Position (Top, Bottom, include position on pipe, 6 O'clock): Bottom 6 O'clock (1)  Description of Failure (Corrosion Gouge, Seam Split): (1) External corrosion. Laboratory Analysis: Yes No Performed by: CC Technologies Inc. Preservation of Failed Section or Component: Yes No If Yes - Method: Wrapped In Custody of: Panhandle Develop a sketch of the area including distances from roads, houses, stress inducing factors, pipe configurations, etc. Bar Hole Test Survey Plot should be outlined with concentrations at test points. Direction of Flow. Component Failure Description N/A Component Failed: (1) Manufacturer: Model: Pressure Rating: Size Other (Breakout Tank, Underground Storage): Pipe Data N/A Material: steel Wall Thickness/SDR: 0.281- inch Diameter (O.D.): 24-inch Installation Date: 1937 SMYS: 48,000 Manufacturer: A. O. Smith Longitudinal Seam: Electric Flash Weld Type of Coating: Coal Tar Pipe Specifications (API 5L, ASTM A53, etc.): API 5L, X48 Joining N/A Type: Girth weld with Coupling every other joint Procedure: NDT Method: Unknown Inspected: Yes No - 5 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Pressure @ Time of Failure @ Failure Site N/A Pressure @ Failure Site: 795 psig at the Houstonia Station Elevation @ Failure Site: 660 Pressure Readings @ Various Locations: Direction from Failure Site Location/M.P./Station # Pressure (psig) Elevation (ft msl) Upstream Downstream N/A Upstream Pump Station Data N/A Type of Product: API Gravity: Specific Gravity: Flow Rate: Pressure @ Time of Failure (4) Distance to Failure Site: High Pressure Set Point: Low Pressure Set Point: Upstream Compressor Station Data N/A Specific Gravity: .55 Flow Rate: Pressure @ Time of Failure (4) 795 psig Distance to Failure Site: 21.6 miles High Pressure Set Point: 830 psig Low Pressure Set Point: Operating Pressure N/A Max. Allowable Operating Pressure: 800 psig Determination of MAOP: 192.619 (c) Actual Operating Pressure: 795 psig Method of Over Pressure Protection: Engine safeties - first engine speed and torque, then shutdown. Relief Valve Set Point: 830 psig Capacity Adequate? Yes No Integrity Test After Failure N/A Pressure Test Conducted in place? (Conducted on Failed Components or Associated Piping): Yes No If NO, Tested after removal? Yes No Method: N/A Describe any failures during the test. Soil/water Conditions @ Failure Site N/A Condition of and Type of Soil around Failure Site (Color, Wet, Dry, Frost Depth): Dry and very rocky Type of Backfill (Size and Description): Rock 4 Obtain event logs and pressure recording charts - 6 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Soil/water Conditions @ Failure Site N/A Type of Water (Salt, Brackish): N/A Water Analysis (5) Yes No External Pipe or Component Examination N/A External Corrosion? Yes No (1) Coating Condition (Disbonded, Non-existent): Coal tar - some disbonded (1) Description of Corrosion: The failed pipeline segments showed multiple areas of external corrosion with reduced wall thickness. Description of Failure Surface (Gouges, Arc Burns, Wrinkle Bends, Cracks, Stress Cracks, Chevrons, Fracture Mode, Point of Origin): A 23 foot section of pipe was ejected and completely ruptured by the failure. Chevrons along the rupture pointed toward the origin in an area of external corrosion with reduced wall thickness. Above Ground: Yes No (1) Buried: Yes No (1) Stress Inducing Factors: (1) Depth of Cover: 6 feet (1) Cathodic Protection N/A P/S (Surface): Readings taken this Spring were adequate - > .85 V - Recent reading in the area -2.1 V 3/26/08 P/S (Interface): Not taken Soil Resistivity: No soil - rock pH: Date of Installation: 1955 Method of Protection: Rectifiers Did the Operator have knowledge of Corrosion before the Incident? Yes No How Discovered? (Close Interval Survey, Instrumented Pig, Annual Survey, Rectifier Readings, ECDA, etc): A close interval survey was performed in 2000 from 2 Gate to 3 Gate. Some areas of low pipe to soil potential were found but not in the area of the failure. See Appendix D. Internal Pipe or Component Examination N/A Internal Corrosion: Yes No (1) Injected Inhibitors: Yes No Type of Inhibitors: N/A Testing: Yes No Results (Coupon Test, Corrosion Resistance Probe): N/A Description of Failure Surface (MIC, Pitting, Wall Thinning, Chevrons, Fracture Mode, Point of Origin): The cause of the failure was external corrosion with reduced wall thickness. Cleaning Pig Program: Yes No Gas and/or Liquid Analysis: Yes No 5 Attach copy of water analysis report - 7 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Internal Pipe or Component Examination N/A Results of Gas and/or Liquid Analysis (6) N/A Internal Inspection Survey: Yes No Results (7) ILI had been scheduled but not done. Did the Operator have knowledge of Corrosion before the Incident? Yes No How Discovered? (Instrumented Pig, Coupon Testing, ICDA, etc.): N/A Outside Force Damage N/A Responsible Party: Telephone No.: Address: Work Being Performed: Equipment Involved: (1) Called One Call System? Yes No One Call Name: One Call Report # (8) Notice Date: Time: Response Date: Time: Details of Response: Was Location Marked According to Procedures? Yes No Pipeline Marking Type: (1) Location: (1) State Law Damage Prevention Program Followed? Yes No No State Law Notice Required: Yes No Response Required: Yes No Was Operator Member of State One Call? Yes No Was Operator on Site? Yes No Did a deficiency in the Public Awareness Program contribute to the accident? Yes No Is OSHA Notification Required? Yes No 6 Attach copy of gas and/or liquid analysis report 7 Attach copy of internal inspection survey report 8 Attach copy of one-call report - 8 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Natural Forces N/A Description (Earthquake, Tornado, Flooding, Erosion): Failure Isolation N/A Squeeze Off/Stopple Location and Method: Panhandle isolated the failure by manually closing 2 Gate and 3 Gate. (1) Valve Closed - Upstream: 2 Gate Time: 9:38 AM I.D.: M.P.: 12.97 Valve Closed - Downstream: 3 Gate Time: 9:23 I.D.: M.P.: 28.43 Pipeline Shutdown Method: Manual Automatic SCADA Controller ESD Failed Section Bypassed or Isolated: Isolated Performed By: Field Tech. Valve Spacing: 16 miles Odorization N/A Gas Odorized: Yes No Concentration of Odorant (Post Incident at Failure Site): Method of Determination: Yes No % LEL: Yes No % Gas In Air: Yes No Time Taken: Yes No Was Odorizer Working Prior to the Incident? Type of Odorizer (Wick, By-Pass): Yes No Odorant Manufacturer: Model: Type of Odorant: Amount Injected: Monitoring Interval (Weekly): Odorization History (Leaks Complaints, Low Odorant Levels, Monitoring Locations, Distances from Failure Site): - 9 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Odorization N/A Weather Conditions N/A Temperature: 85 F Wind (Direction & Speed): light Climate (Snow, Rain): Sunny Humidity: Was Incident preceded by a rapid weather change? Yes No Weather Conditions Prior to Incident (Cloud Cover, Ceiling Heights, Snow, Rain, Fog): Clear Gas Migration Survey N/A Bar Hole Test of Area: Yes No Equipment Used: Method of Survey (Foundations, Curbs, Manholes, Driveways, Mains, Services) (9) (1) Environment Sensitivity Impact N/A Location (Nearest Rivers, Body of Water, Marshlands, Wildlife Refuge, City Water Supplies that could be or were affected by the medium loss): (1) OPA Contingency Plan Available? Yes No Followed? Yes No Class Location/High Consequence Area N/A Class Location: 1 2 3 4 Determination: HCA Area? Yes No N/A Determination: Odorization Required? Yes No N/A Pressure Test History N/A (Expand List as Necessary) 9 Plot on site description page - 10 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Pressure Test History N/A (Expand List as Necessary) Req’d (10)Assessment Deadline Date Test Date Test Medium Pressure (psig) Duration (hrs) % SMYS Installation N/A Next N/A 1955 Water Unknown Unknown Unknown Next Most Recent Describe any problems experienced during the pressure tests. Hydrostatic test done in 1955 - details unknown. Internal Line Inspection/Other Assessment History N/A (Expand List as Necessary) Req’d (10) Assessment Deadline Date Assessment Date Type of ILI Tool (11) Other Assessment Method (12) Indicated Anomaly If yes, describe below Initial 2012 Yes No Next Yes No Next Yes No Most Recent Yes No Describe any previously indicated anomalies at the failed pipe, and any subsequent pipe inspections (anomaly digs) and remedial actions. Not scheduled until 2012. Not in top 50%. Gauge tool run already. Pre-Failure Conditions and Actions N/A Was there a known pre-failure condition requiring (10) the operator to schedule evaluation and remediation? Yes (describe below or on attachment) No If there was such a known pre-failure condition, had the operator established and adhered to a required (10) evaluation and remediation schedule? Describe below or on attachment. Yes No N/A Prior to the failure, had the operator performed the required (10) actions to address the threats that are now known to be related to the cause of this failure? Yes No N/A List below or on an attachment such operator-identified threats, and operator actions taken prior to the accident. Describe any previously indicated anomalies at the failed pipe, and any subsequent pipe inspections (anomaly digs) and remedial actions. N/A Maps & Records N/A 10 As required of Pipeline Integrity Management regulations in 49CFR Parts 192 and 195 11 MFL, geometry, crack, etc. 12 ECDA, ICDA, SCCDA, “other technology,” etc. - 11 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Are Maps and Records Current? (13) Yes No Comments: Leak Survey History N/A Leak Survey History (Trend Analysis, Leak Plots): Leak survey on 6/25/2007. No leaks were found in the area of the failure. Pipeline Operation History N/A Description (Repair or Leak Reports, Exposed Pipe Reports): N/A Did a Safety Related Condition Exist Prior to Failure? Yes No Reported? Yes No Unaccounted For Gas: None before the incident. Over & Short/Line Balance (24 hr., Weekly, Monthly/Trend): Operator/Contractor Error N/A Name: Job Function: Title: Years of Experience: Training (Type of Training, Background): Was the person “Operator Qualified” as applicable to a precursor abnormal operating condition? Yes No N/A Was qualified individual suspended from performing covered task Yes No N/A Type of Error (Inadvertent Operation of a Valve): Procedures that are required: Actions that were taken: Pre-Job Meeting (Construction, Maintenance, Blow Down, Purging, Isolation): Prevention of Accidental Ignition (Tag & Lock Out, Hot Weld Permit): Procedures conducted for Accidental Ignition: Was a Company Inspector on the Job? Yes No Was an Inspection conducted on this portion of the job? Yes No 13 Obtain copies of maps and records - 12 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Operator/Contractor Error N/A Additional Actions (Contributing factors may include number of hours at work prior to failure or time of day work being conducted): Training Procedures: Operation Procedures: Controller Activities: Name Title Years Experience Hours on Duty Prior to Failure Shift Alarm Parameters: High/Low Pressure Shutdown: Flow Rate: Procedures for Clearing Alarms: Type of Alarm: Company Response Procedures for Abnormal Operations: Over/Short Line Balance Procedures: Frequency of Over/Short Line Balance: Additional Actions: Additional Actions Taken by the Operator N/A Make notes regarding the emergency and Failure Investigation Procedures (Pressure reduction, Reinforced Squeeze Off, Clean Up, Use of Evacuators, Line Purging, closing Additional Valves, Double Block and Bleed, Continue Operating downstream Pumps): - 13 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Additional Actions Taken by the Operator N/A The failure was detected by Gas Control in Houston at 8:51 a.m. on 8/25/2008. Field crews located the failure at 9:10 a.m. The failure was isolated by closing valves at about 9:30 a.m. Panhandle sent a team to investigate the failure on 8/26/08. After the initial investigation, the pipeline was repaired and returned to service at 80% of the pressure at the time of the incident (795 psi) pending the results of the investigation. - 14 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Photo Documentation (1) Overall Area from best possible view. Pictures from the four points of the compass. Failed Component, Operator Action, Damages in Area, Address Markings, etc. Photo No. Description Roll No. Photo No. Description Roll No. 1 View looking west at the crater 1 2 East view of exposed pipe in crater 2 3 West view of exposed pipe in crater 3 4 View of longer ejected pipe segment 4 5 Close view of longer segment 5 6 View of shorter ejected segment 6 7 Another view of shorter segment 7 8 Possible failure origin on shorter segment 8 9 Side view of possible failure. 9 10 View of coupling ejected into the woods 10 11 Close up of corrosion at possible failure origin. 11 12 View of another area of external corrosion near the failure origin 12 13 View of failure origin after the pipe was moved. 13 14 14 15 15 16 16 17 17 18 18 19 19 20 20 21 21 22 22 23 23 24 24 25 25 26 26 27 27 28 28 29 29 30 30 Type of Camera: - 15 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Photo Documentation (1) Film ASA: Video Counter Log (Attach Copy): Additional Information Sources Agency Name Title Phone Number Police: Cooper County Sheriff Fire Dept.: Pilot Grove Fire Dept State Fire Marshall: State Agency: Missouri DOT Emergency Response Team NTSB: EPA: FBI: ATF: OSHA: Insurance Co.: FRA: MMS: Television: No Newspaper: Other: - 16 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Persons Interviewed Name Title Phone Number Brad Howard Operations Specialist 660-568-1221 Mike Dawson Steve Atkinson Technical Specialist Jerry Rau Director Pipeline Integrity 913-906-1522 713-989-7417 Rob Wesch Liz Rutherford Brian Kraft Measurement Tech Dan Corpening Area Director Ross Cummins CP Tech Richard Gifford Corrosion Tech Gerald Moore Environmental Coordinator - 17 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Event Log Sequence of events prior, during, and after the incident by time. (Consider the events of all parties involved in the incident, Fire Department and Police reports, Operator Logs and other government agencies.) Time Event 8:51 a.m. 8/25/08 Gas Control detects a pressure drop on the Houstonia 200 line and asks field techs to check for a leak. 9:00 a.m. Filed techs hear blowing gas near mile post 21.6 9:10 a.m. Field techs locate the failure 9:23 a.m. 3 Gate at MP 28.43 is closed manually 9:38 a.m. 2 Gate at MP 12.97 is closed manually 9:00 -11:00 a.m. Panhandle, Fire and police check the area to see if evacuations are necessary 1:00 p.m. PHMSA investigator arrives on site. 1:00 - 8:00 p.m. Investigation by PHMSA and Panhandle 12:00 p.m. 8/26 Panhandle investigation team from Houston arrives 12:00 - 7:00 p.m. Investigation of the failure site by PHMSA and Panhandle. - 18 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Investigation Contact Log Time Date Name Description 1:00 p.m. 8/26/08 Brad Howard Operations Specialist 1:30 p.m. 8/26/08 Steve Atkinson Technical Specialist 12:00 p.m. 8/27/08 Jerry Rau Director Pipeline Integrity 1:00 p.m. 8/26- 10/20 Brad Howard Follow up on various issues 10:00 a.m. 9/26/08 David McQuilling Principal Engineer - conference call on cathodic protection 10:00 a.m. 9/26/08 Steve Atkinson Same conference call. - 19 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Failure Investigation Documentation Log Operator: Unit #: CPF #: Date: Appendix Number Documentation Description Date FOIA Received Yes No A Investigation Pictures 8/25/08 X B Panhandle Incident Report 9/18/08 X C Panhandle Laboratory Failure Analysis 10/29/08 X D Panhandle Close Interval Survey 9/18/08 X - 20 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Site Description Provide a sketch of the area including distances from roads, houses, stress inducing factors, pipe configurations, etc. Bar Hole Test Survey Plot should be outlined with concentrations at test points. Photos should be taken from all angles with each photo documented. Additional areas may be needed in any area of this guideline. The Failure location was about two miles northwest of Pilot Grove (Cooper County) Missouri near Highway HH. The location was near milepost 21.6 on the Houstonia 200 line on a rocky hillside in a rural area. No structures were close to the failure location. The following page shows a sketch of the location provided by Panhandle. The image below shows the Panhandle system map. Panhandle Eastern Pipe Line Company, LP Panhandle Eastern Pipe Line Company operates a 6,500-mile pipeline system with access to diverse supply sources and can deliver 2.8 Bcf/d of natural gas to Midwest and East Coast markets. Tie-ins to Chicago, Dayton and Cincinnati have added to a Midwest customer base that includes some of the nation's largest utility and industrial natural gas users. We lead the way in offering competitive rates and a constantly evolving array of customer-friendly service options. Panhandle Eastern provides:  Access to diverse Midcontinent and Canadian supply sources and to major Midwest and Northeast markets.  Access to 74 Bcf of storage facilities. To request a receipt and delivery point map, please contact Customer Service at 1-800-275-7375. - 21 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report - 22 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Appendix A Houstonia 200 failure Pictures – 8/25/08 near Pilot Grove MO. - 23 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report 8/25/08 – #1- views looking West at the crater caused by the Houstonia 200 failure. - 24 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report 8/25/08 #2 - East view of the exposed pipe. 8/25/08 #3 -West close up. - 25 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report 8/25/08 #4 - One of two pipe sections ejected – the longer one – about 30 feet. 8/25/08 #5 -Closer view of the longer ejected section. - 26 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report 8/25/08 #6 -View of the shorter section ejected – about 23 feet – ruptured full length. 8/25/08 #7 -Another view of same looking north. - 27 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report #8 - Areas with external corrosion and reduced wall thickness – possible failure origin. 8/25/08 #9 -Side view of the failure origin site with reduced wall thickness. - 28 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report 8/25/08 #10 -View of coupling ejected from pipeline. 8/25/08 #11 -Close up of external corrosion on the possible origin site. - 29 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report 8/25/08 #12 - Another area of external corrosion on the shorter section near the possible failure. 8/26/08 #13 -Different view of the possible failure origin after the pipe was turned over. - 30 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Pipeline Failure Investigation Report Appendix B Panhandle Incident Report - 31 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> NOTICE: This report is required by 49 CFR Part 191. Failure to report can result in a civil penalty not to exceed $25,000 for each violation for each day that such violation persists except that the maximum civil penalty shall not exceed $500,000 as provided in 49 USC 1678. Form Approved OMB No. 2137-0522 U.S. Department of Transportation Research and Special Programs Administration INCIDENT REPORT - GAS TRANSMISSION AND GATHERING SYSTEMS Report Date No. (DOT Use Only) INSTRUCTIONS Important: Please read the separate instructions for completing this form before you begin. They clarify the information requested and provide specific examples. If you do not have a copy of the instructions, you can obtain one from the Office Of Pipeline Safety Web Page at http://ops.dot.gov . Nearest street or road City and County or Parrish a. b. c. State and Zip Code d. Mile Post/Valve Station e. Survey Station No. f. Latitude: Longitude: (if not available, see instructions for how to provide specific location) g. Class location description Onshore: Class 1 Class 2 Class 3 Class 4 Offshore: Class 1 (complete rest of this item) Area ___________________ Block # ___________ State / / or Outer Continental Shelf h. Incident on Federal Land other than Outer Continental Shelf Yes No i. Is pipeline Interstate Yes No 4. Type of leak or rupture Leak: Pinhole Connection Failure (complete sec. F5) Puncture, diameter (inches) Rupture: Circumferential – Separation Longitudinal – Tear/Crack, length (inches) Propagation Length, total, both sides (feet) N/A Other: PART A – GENERAL REPORT INFORMATION Operator Name and Address Original Report Supplemental Report Final Report a. Operator's 5-digit Identification Number (when known) / / b. If Operator does not own the pipeline, enter Owner’s 5-digit Identification Number (when known) / / c. Name of Operator ______________________________ _______________________________________________________ d. Operator street address ________________________________________________________________________________________ e. Operator address _______________________ City, County or Parrish, State and Zip Code 2. Time and date of the incident / / / / / / / / hr. month day year 3. Location of incident 5. Consequences (check and complete all that apply) a. Fatality Total number of people: / / Employees: / / General Public: / / Non-employee Contractors: / / b. Injury requiring inpatient hospitalization Total number of people: / / Employees: / / General Public: / / Non-employee Contractors: / / c. Property damage/loss (estimated) Total $ Gas loss $ Operator damage $ Public/private property damage $ d. Release Occurred in a ‘High Consequence Area’ e. Gas ignited – No explosion f. Explosion g. Evacuation (general public only) / / people Reason for Evacuation: Emergency worker or public official ordered, precautionary Threat to the public Company policy 6. Elapsed time until area was made safe: / / hr. / / min. 7. Telephone Report / / / / / / / / NRC Report Number month day year 8. a. Estimated pressure at point and time of incident: PSIG b. Max. allowable operating pressure (MAOP): PSIG c. MAOP established by 49 CFR section: 192.619 (a)(1) 192. 619 (a)(2) 192. 619 (a)(3) 192.619 (a)(4) 192. 619 (c) d. Did an overpressurization occur relating to the incident? Yes No PART B – PREPARER AND AUTHORIZED SIGNATURE (type or print) Preparer's Name and Title Preparer's E-mail Address Area Code and Telephone Number Area Code and Facsimile Number Date Area Code and Telephone Number Authorized Signature (type or print) Name and Title Form RSPA F 7100.2 ( 01-2002 ) OPS Data Facsimile Page 1 of 3 <<>> PART C - ORIGIN OF THE INCIDENT 1. Incident occurred on Transmission System Gathering System Transmission Line of Distribution System 2. Failure occurred on Body of pipe Pipe Seam Joint Component Other: 3. Material involved (pipe, fitting, or other component) Steel Plastic (If plastic, complete all items that apply in a-c) Plastic failure was: a.ductile b.brittle c.joint failure Material other than plastic or steel: _________ 4. Part of system involved in incident Pipeline Regulator/Metering System Compressor Station Other: 5. Year the pipe or component which failed was installed: / / PART D – MATERIAL SPECIFICATION (if applicable) 1. Nominal pipe size (NPS) / / in. 2. Wall thickness / / in. 3. Specification SMYS / / 4. Seam type 5. Valve type 6. Pipe or valve manufactured by PART E – ENVIRONMENT 1. Area of incident In open ditch Under pavement Above ground Under ground Under water Inside/under building Other: 2. Depth of cover: inches in year / / PART F – APPARENT CAUSE Important: There are 25 numbered causes in this section. Check the box to the left of the primary cause of the incident. Check one circle in each of the supplemental items to the right of or below the cause you indicate. See the instructions for this form for guidance. F1 – CORROSION 1. External Corrosion 2. Internal Corrosion If either F1 (1) External Corrosion, or F1 (2) Internal Corrosion is checked, complete all subparts a – e. a. Pipe Coating Bare Coated b. Visual Examination c. Cause of Corrosion Galvanic Stray Current Localized Pitting General Corrosion Improper Cathodic Protection Other: ____________________ Microbiological Stress Corrosion Cracking Other: ____________________ d. Was corroded part of pipeline considered to be under cathodic protection prior to discovering incident? No Yes, Year Protection Started: / / e. Was pipe previously damaged in the area of corrosion? No Yes, How long prior to incident: / / years / / months F2 – NATURAL FORCES 3. Earth Movement => Earthquake Subsidence Landslide Other: 4. Lightning 5. Heavy Rains/Floods => Washouts Flotation Mudslide Scouring Other: 6. Temperature => Thermal stress Frost heave Frozen components Other: 7. High Winds F3 - EXCAVATION 8. Operator Excavation Damage (including their contractors) / Not Third Party 9. Third Party Excavation Damage (complete a-d) a. Excavator group General Public Government Excavator other than Operator/subcontractor b. Type: Road Work Pipeline Water Electric Sewer Phone/Cable Landowner Railroad Other: c. Did operator get prior notification of excavation activity? No Yes: Date received: / / mo. / / day / / yr. Notification received from: One Call System Excavator Contractor Landowner d. Was pipeline marked? No Yes (If Yes, check applicable items i – iv) i. Temporary markings: Flags Stakes Paint ii. Permanent markings: Yes No iii. Marks were (check one) Accurate Not Accurate iv. Were marks made within required time? Yes No F4 – OTHER OUTSIDE FORCE DAMAGE 10. Fire/Explosion as primary cause of failure => Fire/Explosion cause: Man made Natural 11. Car, truck or other vehicle not relating to excavation activity damaging pipe 12. Rupture of Previously Damaged Pipe 13. Vandalism Form RSPA F 7100.2 ( 01-2002 ) Page 2 of 3 <<>> F5 – MATERIAL AND WELDS Material 14. Body of Pipe => Dent Gouge Wrinkle Bend Arc Burn Other: 15. Component => Valve Fitting Vessel Extruded Outlet Other: 16. Joint => Gasket O-Ring Threads Other: Weld 17. Butt => Pipe Fabrication Other: 18. Fillet => Branch Hot Tap Fitting Repair Sleeve Other: 19. Pipe Seam => LF ERW DSAW Seamless Flash Weld HF ERW SAW Spiral Other: Complete a-g if you indicate any cause in part F5. a. Type of failure: Construction Defect => Poor Workmanship Procedure not followed Poor Construction Procedures Material Defect b. Was failure due to pipe damage sustained in transportation to the construction or fabrication site? Yes No c. Was part which leaked pressure tested before incident occurred? Yes, complete d-g No d. Date of test: / / mo. / / day / / yr. e. Test medium: Water Natural Gas Inert Gas Other: f. Time held at test pressure: / / hr. g. Estimated test pressure at point of incident: PSIG F6 – EQUIPMENT AND OPERATIONS 20. Malfunction of Control/Relief Equipment => Valve Instrumentation Pressure Regulator Other: 21. Threads Stripped, Broken Pipe Coupling => Nipples Valve Threads Mechanical Couplings Other: 22. Ruptured or Leaking Seal/Pump Packing 23. Incorrect Operation a. Type: Inadequate Procedures Inadequate Safety Practices Failure to Follow Procedures Other: b. Number of employees involved who failed post-incident drug test: / / Alcohol test: / / c. Were most senior employee(s) involved qualified? Yes No d. Hours on duty: / / F7 – OTHER 24. Miscellaneous, describe: 25. Unknown Investigation Complete Still Under Investigation (submit a supplemental report when investigation is complete) PART G – NARRATIVE DESCRIPTION OF FACTORS CONTRIBUTING TO THE EVENT (Attach additional sheets as necessary) Form RSPA F 7100.2 ( 01-2002 ) OPS Data Facsimile Page 3 of 3 <<>> Pipeline Failure Investigation Report Appendix C Panhandle Failure Analysis - 32 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08) <<>> Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Panhandle Eastern Pipe Line Company, LP Final Report – 813 8385 1 October 29, 2008 . <<>> CC TECHNOLOGIES, INC. Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) for Panhandle Eastern Pipe Line Company, L.P. 5444 Westheimer, Suite 432 Houston, TX 77056 5777 Frantz Road Dublin, Ohio 43017-1386 U.S.A. Tel: (614) 761-1214 Fax: (614) 761-1633 www.dnv.com www.cctechnologies.com Summary: Final Report Prepared by: Gregory T. Quickel, M.S. Staff Engineer Reviewed by: John Beavers, Ph.D., FNACE . Director – Failure Analysis Approved by: Patrick H. Vieth Senior VP – Integrity & Materials Date of Issue: October 29, 2008 Project Number: 813 8385 1 No distribution without permission from the client or responsible organizational unit (however, free distribution for internal use within DNV after 3 years) No distribution without permission from the client or responsible organizational unit Strictly confidential Unrestricted distribution All copyrights reserved CC Technologies, Inc. This publication, or parts thereof, may not be reproduced or transmitted in any form or by any means, including photocopying or recording, without the prior written consent of CC Technologies, Inc. Reference to part of this report, which may lead to misinterpretation, is not permissible. Q:\EAWUS813\Anderson\2008\GREG QUICKEL\PANHANDLE EASTERN PIPE LINE CO (813 8385 1) October 22\Panhandle Final Report (813 8385 1) (October 29).doc <<>> Page ii Disclaimer This report documents work performed by CC Technologies, Inc. (CC Technologies) Dublin, Ohio, for Panhandle Eastern Pipe Line Company, L.P. (Panhandle) Houston, Texas. Neither CC Technologies nor any person acting on behalf of CC Technologies: • assumes any liability for consequences or damages resulting from the use, misuse, or reliance upon the information disclosed in this report. • makes any warranty or representations that the use of any information, apparatus, method, or process disclosed in this report may not infringe on privately-owned rights. CC TECHNOLOGIES, INC. <<>> Page iii Executive Summary Panhandle Eastern Pipe Line Company, L.P (Panhandle) retained CC Technologies, Inc. (CC Technologies) to perform a metallurgical analysis on a section of pipe from the 24-inch diameter Houstonia 200 natural gas pipeline that failed during service. The failure occurred on August 25, 2008 near Pilot Grove (Cooper County), Missouri at milepost (MP) 21.6. The portion of the pipeline containing the failure is comprised of 24-inch diameter by 0.281-inch wall thickness line pipe with an estimated yield strength (EYS) of 48.0 ksi that was manufactured by A.O. Smith and contains an electric flash welded (EFW) - **truncated:** true - **body characters:** 89544