Natural Gas Pipeline Accident
Investigations – Perspectives and
Recommendations
John B. Vorderbrueggen, PE
Chief, Pipeline and Hazardous Materials
Investigations
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WRGC
August 20, 2013
A Short NTSB Overview
How old is the NTSB?
A. 30 years
B. 39 years
C. 73 years
D. 87 years
E. 95 years
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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
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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
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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
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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
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NTSB Transportation Modes
• Aviation
• Marine
• Highway
• Railroad
• Pipeline and Hazardous Materials
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Other NTSB Offices
• Research and Engineering
− Safety Research and Satirical
Analysis
− Vehicle performance
− Vehicle recorders
− Materials laboratory
− Medical Investigations
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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
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The NTSB Board Members
August 2013
Hon. Deborah A. P. Hersman
Acting Chairman
Hon. Robert L. Sumwalt
Hon. Christopher A. Hart
Hon. Mark R. Rosekind
Hon. Earl F. Weener
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Natural Gas Transmission Pipeline
Accidents
San Bruno, California
Palm City, Florida
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Pacific Gas and Electric Company
Natural Gas Transmission Pipeline
Rupture and Fire
San Bruno, California
September 9, 2010
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Pipe Segment
Crater
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Claremont Drive
Earl Avenue
RUPTURE
Glenview Drive
Accident Consequences
• Eight fatalities
• Dozens injured
• 38 homes destroyed
• More than 70 homes damaged
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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
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Events Prior to the Rupture
• Electrical maintenance work at Milpitas
Terminal
• Power supply units interrupted
• Line discharge pressure climbed
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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
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Undocumented Configuration
North joint
Pup 6
Pup 5
Pup 4
Pup 3
4½ feet
Pup 2
Pup 1
3½ - 4 feet each
South joint
Rupture initiation
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Comparison of Pipe Attributes
Section
South joint
DSAW
seam weld

Rolling
direction

Yield
strength
Weld
hardness






Pup 1
Pup 2
Pup 3
Pup 4
Pup 5
Pup 6
North joint




No record of material supplier, material
pedigree, or fabrication records
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Typical DSAW Seam Weld
Raised weld reinforcement
Outer wall
Weld metal
(first pass)
Weld metal
Inner wall
(second pass)
Raised weld reinforcement
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Incomplete Pup 1 Seam Weld
No weld reinforcement
Outer wall
Fracture through weld
Unwelded region
Inner wall
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Fit-up angle
Identified Safety Issues
• Multiple deficiencies in PG&E
operations practices
• Federal and state regulatory
oversight weakness
• Deficient federal pipeline safety rules
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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
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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
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Probable Cause (cont.)
Inadequate pipeline integrity
management program
− PG&E failed to detect and repair, or
remove the defective pipe
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Probable Cause (cont.)
Contributing to the accident
• CPUC failed to detect the
inadequacies of the PG&E
pipeline integrity management
program
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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
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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
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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)
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Final Report Recommendations
• The U.S. Department of
Transportation (4)
• The Pipeline and Hazardous
Materials Safety Administration
(13)
• The State of California (1)
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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)
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Florida Gas Transmission Company
Pipeline Rupture
Palm City, Florida
May 4, 2009
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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
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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
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Pipeline Configuration
• Three parallel, interconnected lines
• Dual pressure-reducing regulators
protected lower MAOP on 18 inch
line
• Normal flow demand (pressure)
fluxuations expected
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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.
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Ongoing Investigations
• Cleburne, Texas
Enterprise Products Operating, LTD
June 7, 2010
One Fatality
• Sissonville, West Virginia
Columbia Gas Transmission
December 11, 2012
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The NTSB Perspective
Most Wanted List – Pipeline Safety
• PHMSA and State regulators must
improve industry oversight
− effective performance-based standards
− adequacy of integrity management
and inspection protocols
− ensure deficiencies are promptly
corrected
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
John B. Vorderbrueggen, PE
Chief, Pipeline and Hazardous
Materials Investigations
202-314-6467
John.vorderbrueggen@ntsb.gov
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