Natural Gas Pipeline Accident Investigations – Perspectives and Recommendations

1. Natural Gas Pipeline Accident Investigations – Perspectives and Recommendations • John B. Vorderbrueggen, PE • Chief, Pipeline and Hazardous Materials Investigations • WRGC August 20, 2013

2. A Short NTSB Overview How old is the NTSB? • 30 years • 39 years • 73 years • 87 years • 95 years

3. Origin of the NTSB • Air Commerce Act of 1926U.S. Department of Commerce shall investigate aircraft accidents • 1940 - Investigations assigned to the Civil Aeronautics Board Bureau of Aviation Safety

4. Origin of the NTSB • 1967 - NTSB embedded in the U.S. Department of Transportation • 1974 - NTSB reestablished as an independent, Executive Branch agency • U.S. Code Title 49, Chapter 11

5. NTSB Improvements • 1996 – Coordinate assistance to families of aviation accident victims • 2000 – Created the NTSB Training Academy (NTSB Training Center) • GW University Campus in Ashburn, VA • Improve employee technical skills • Provide investigation expertise to industry

6. NTSB Features • Independent Federal Agency • Does not regulate transportation equipment, personnel, or operations • No official role in establishing and enforcing industry regulations • Does not initiate enforcement action • Issues and tracks Recommendations

7. NTSB Transportation Modes • Aviation • Marine • Highway • Railroad • Pipeline and Hazardous Materials

8. Other NTSB Offices • Research and Engineering • Safety Research and Satirical Analysis • Vehicle performance • Vehicle recorders • Materials laboratory • Medical Investigations

9. Other NTSB Offices • Administrative Law Judges • “Court of appeal" for airmen, mechanics or mariners for certificate actions • Hear, consider, and issue initial decisions on appeals • Adjudicate claims for fees and expenses from FAA certificate and civil penalty actions

10. The NTSB Board MembersAugust 2013 Hon. Deborah A. P. HersmanActing Chairman Hon. Robert L. Sumwalt Hon. Christopher A. Hart Hon. Mark R. Rosekind Hon. Earl F. Weener

11. Natural Gas Transmission Pipeline Accidents San Bruno, California Palm City, Florida

12. Pacific Gas and Electric Company Natural Gas Transmission Pipeline Rupture and Fire San Bruno, CaliforniaSeptember 9, 2010

13. Pipe Segment Crater

15. Claremont Drive Earl Avenue RUPTURE Glenview Drive

16. Accident Consequences • Eight fatalities • Dozens injured • 38 homes destroyed • More than 70 homes damaged

18. Ruptured Pipeline Details • 30-inch diameter, 0.375-inch wall • Installed in 1956 • API Grade X42, carbon steel • Documents listed seamless pipe • Other inaccurate fabrication records

19. Events Prior to the Rupture • Electrical maintenance work at Milpitas Terminal • Power supply units interrupted • Line discharge pressure climbed

20. Accident Event Timeline • 5:45 p.m. pressure rose above 375 psi • 6:11 p.m. pipeline ruptured when pressure reached 386 psi • 7:30 p.m. upstream valve closed • 7:46 p.m. downstream valves closed

21. Undocumented Configuration North joint Earl Ave Pup 6 Pup 5 Pup 4 Glenview Dr Pup 3 4½ feet Pup 2 Pup 1 3½ - 4 feet each South joint Rupture initiation N W E S 21

22. Comparison of Pipe Attributes     ?         • No record of material supplier, material pedigree, or fabrication records 22

23. Typical DSAW Seam Weld Raised weld reinforcement Outer wall Weld metal (first pass) Weld metal (second pass) Inner wall Raised weld reinforcement 23

24. Incomplete Pup 1 Seam Weld Fracture through weld No weld reinforcement Outer wall Fit-up angle Unwelded region Inner wall 24

25. Identified Safety Issues • Multiple deficiencies in PG&E operationspractices • Federal and state regulatory oversight weakness • Deficient federal pipeline safety rules

26. Other Shortcomings • PG&E integrity management, threat identification, record keeping, dispatch procedures • CPUC hydrotest exemption for pre-1961 pipelines • DOT grandfather hydrotest exemption for pre-1970 pipelines

27. Probable Cause Inadequate quality assurance and quality control in 1956 pipe relocation • Substandard longitudinal pipe joint with a visible weld flaw that grew to a critical size • Pipeline ruptured when poorly planned electrical work at the Milpitas Terminal caused an unplanned pressure increase

28. Probable Cause (cont.) Inadequate pipeline integrity management program • PG&E failed to detect and repair, or remove the defective pipe

29. Probable Cause (cont.) Contributing to the accident • CPUC failed to detect the inadequacies of the PG&E pipeline integrity management program

30. Probable Cause (cont.) • California Public Utilities Commission and the U.S. DOT exemptions from pipeline pressure testing of existing pipelines • Hydrotest would likely have identified the installation defects

31. Probable Cause (cont.) Contributing to the severity of the accident • Lack of automatic shutoff valves or remote controlled valves • Flawed PG&E emergency response procedures • Delay in isolating the rupture

32. Pre-report Recommendations • Pipeline and Hazardous Materials Safety Administration (2 Early, 1 Urgent) • California Public Utilities Commission (3 Urgent) • Pacific Gas and Electric Company (2 Early, 2 Urgent)

33. Final Report Recommendations • The U.S. Department of Transportation (4) • The Pipeline and Hazardous Materials Safety Administration (13) • The State of California (1)

34. Recommendations (cont.) • The California Public Utilities Commission (2) • The Pacific Gas and Electric Company (8) • The American Gas Association and the Interstate Natural Gas Association of America (1)

35. Florida Gas Transmission CompanyPipeline RupturePalm City, FloridaMay 4, 2009

37. Pipeline Details • 18-inch diameter carbon steel, 0.25-inch wall thickness, API 5LX, 1959 installation • Hydrotested at 1085 psig • 1971 hydrotestedat 1320 psig - 866 psig MAOP

38. Pipeline Details • Polyethylene tape coated and cathodically protected • 2004 Magnetic flux leakage in-line inspection • Postaccident metallurgy identified replaced segments but no record of the change

42. Pipeline Configuration • Three parallel, interconnected lines • Dual pressure-reducing regulators protected lower MAOP on 18 inch line • Normal flow demand (pressure) fluxuations expected

44. System Response to the Rupture • Line break actuator closed upstream ASV within two minutes • Downstream actuator failed to activate • FGT crew closed valve two hours later

45. Post-Accident System Test • Downstream ASV operated as designed • Rate-of-pressure drop setpoint was most likely above the accident pressure decay rate • Pressure decay dependent on looped system interaction

46. SCADA System • No position indication on mainline valves or cross-connect regulators • Controllers were unaware of ASV closure and the full-open regulators • No alarms sounded • Pressure scan rate too low to detect short duration pressure drop

47. Postaccident Pipe Inspection • No internal corrosion • External corrosion pitting under damaged coating • 30 percent wall thinning along longseam, below minimum required • Magnetic particle inspection identified longitudinal cracks along longitudinal weld

48. Class Location • Ruptured pipe assigned Class 1, no HCA sites • Integrity management not required • Baseline in-line inspection was performed • Mainline valve spacing for Class 1 • Class 3 applied - school within 366 feet

50. Integrity Management Program • Stress corrosion cracking was not considered a significant risk • 2004 caliper tool and axial MFL in-line inspection – no repairs required in rupture area • Axial MFL does not accurately detect longitudinally oriented stress corrosion cracking