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Natural Gas Pipeline Accident Investigations – Perspectives and Recommendations. John B. Vorderbrueggen, PE Chief, Pipeline and Hazardous Materials Investigations WRGC August 20, 2013. A Short NTSB Overview. How old is the NTSB? 30 years 39 years 73 years 87 years 95 years. - PowerPoint PPT Presentation
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Natural Gas Pipeline Accident Investigations – Perspectives and Recommendations
1
John B. Vorderbrueggen, PEChief, Pipeline and Hazardous Materials InvestigationsWRGC August 20, 2013
2
A Short NTSB Overview
How old is the NTSB?A. 30 years B. 39 yearsC. 73 yearsD. 87 yearsE. 95 years
3
Origin of the NTSB
• Air Commerce Act of 1926 U.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. SumwaltHon. Christopher A. HartHon. Mark R. RosekindHon. Earl F. Weener
Pacific Gas and Electric Company Natural Gas Transmission Pipeline Rupture and Fire San Bruno, CaliforniaSeptember 9, 2010
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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
Undocumented Configuration
South joint
North joint
3½ - 4 feet each
4½ feet
Pup 1
Pup 2
Pup 3
Pup 4Pup 5
Pup 6
N
SW
E
Rupture initiation
Earl Ave
Glenview Dr
21
Comparison of Pipe AttributesSection
DSAW seam weld
Rolling direction
Yield strength
Weld hardness
South joint
Pup 1
Pup 2
Pup 3
Pup 4
Pup 5
Pup 6
North joint
No record of material supplier, material pedigree, or fabrication records
?
22
Typical DSAW Seam Weld
Outer wall
Inner wall
Raised weld reinforcement
Weld metal(first pass)
Weld metal(second pass)
Raised weld reinforcement
23
Incomplete Pup 1 Seam Weld
Outer wall
Inner wall
Unwelded region
No weld reinforcement
Fit-up angle
Fracture through weld
24
25
Identified Safety Issues
• Multiple deficiencies in PG&E operations practices
• 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)
37
Pipeline Details
• 18-inch diameter carbon steel, 0.25-inch wall thickness, API 5LX, 1959 installation
• Hydrotested at 1085 psig• 1971 hydrotested at 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
51
FGT Postaccident Actions• SCADA instrument upgrades on
looped systems• Pressure transmitters installed at
regulators and each parallel line• Valve position sensors installed on
regulators and cross-connect valves• Remote control functionality added
to the cross-connect valve
52
FGT Postaccident Actions• SCADA pressure rate-of-change
alarm configuration revised• Conducted circumferential MFL
inspection • Hydrostatic pressure tested the line
– four failures on the 18-inch pipeline
• Follow-up hydrostatic spike test
53
Probable Cause Pipeline failed due to environmentally assisted cracking under a disbonded polyethylene coating that remained undetected by the integrity management program
The integrity management program incorrectly identified the pipe section as not a high consequence area
54
Probable Cause (cont.)
Contributing to the prolonged gas release was the inability of the pipeline controller to detect the rupture due of limitations in the SCADA system and the configuration of the pipeline.
55
Ongoing Investigations
• Cleburne, Texas Enterprise Products Operating, LTDJune 7, 2010One Fatality
• Sissonville, West VirginiaColumbia Gas TransmissionDecember 11, 2012
• PHMSA and State regulators must improve industry oversight− effective performance-based standards− adequacy of integrity management
and inspection protocols− ensure deficiencies are promptly
corrected
The NTSB PerspectiveMost Wanted List – Pipeline Safety
Pipeline Safety (cont.)
• Operators need to improve emergency response− Faster leak isolation using automatic
and remote shutoff valves− Provide key information on pipelines
to local jurisdictions and residents