Natural Gas Pipeline Accident Investigations – Perspectives and Recommendations

Natural Gas Pipeline Accident Investigations – Perspectives and Recommendations

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John B. Vorderbrueggen, PEChief, Pipeline and Hazardous Materials InvestigationsWRGC August 20, 2013

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A Short NTSB Overview

How old is the NTSB?A. 30 years B. 39 yearsC. 73 yearsD. 87 yearsE. 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 MembersAugust 2013

Hon. Deborah A. P. HersmanActing Chairman

Hon. Robert L. SumwaltHon. Christopher A. HartHon. Mark R. RosekindHon. Earl F. Weener

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Natural Gas Transmission Pipeline Accidents

San Bruno, California

Palm City, Florida

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

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Pipe Segment

Crater

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Glenview Drive

Earl Avenue

Claremont Drive

RUPTURE

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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

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

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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

?

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Typical DSAW Seam Weld

Outer wall

Inner wall

Raised weld reinforcement

Weld metal(first pass)

Weld metal(second pass)

Raised weld reinforcement

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Incomplete Pup 1 Seam Weld

Outer wall

Inner wall

Unwelded region

No weld reinforcement

Fit-up angle

Fracture through weld

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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)

Florida Gas Transmission CompanyPipeline RupturePalm City, FloridaMay 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, 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

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John B. Vorderbrueggen, PEChief, Pipeline and Hazardous

Materials [email protected]