The IIC's associated presentation is also available.
Witness video is footage of the fire caused by the pipeline rupture (on NTSB's YouTube channel)
On September 9, 2010, at approximately 6:11 pm Pacific Daylight Time, a natural gas transmission pipeline owned and operated by Pacific Gas & Electric Company or PG&E ruptured in a residential area in San Bruno, California.
PG&E provides natural gas and electric service to approximately 15 million people throughout a 70,000 square mile service area in northern and central California. Their gas facilities include 42,141 miles of natural gas distribution pipelines and 6,438 miles of transmission pipelines.
The rupture occurred at the intersection of Earl Avenue and Glenview Drive in the city of San Bruno. The rupture is indicated by the white oval. The rupture caused an estimated 47.6 million standard cubic feet of natural gas to be released. The released natural gas ignited, resulting in a fire that destroyed 38 homes shown here in red, and damaged 70 shown here in yellow. Eight people were killed, numerous individuals were injured, and many more were evacuated from the area.
A video of the event was obtained, and has been shortened to give you a sense of the magnitude of the fire. It will play for approximately 1 and-a-half minutes. This video is footage of the fire caused by the pipeline rupture. It is looking East, down Earl Avenue towards the rupture location. This video transitions into a zoomed-in view of the fire, followed by two aerial post-rupture photographs that show the crater caused by the rupture and the surrounding damage. This video contains audio of the rupture.
The section of transmission pipeline that ruptured was part of PG&E's Line 132. Line 132 is approximately 47 miles long and originates at the Milpitas Terminal, located at the bottom right of the slide. The gas flow is from south to north as shown in the slide. Line 132 terminates at the Martin Station, located near the top left corner of the slide.
PG&E's gas transmission pipelines are controlled by a supervisory control and data acquisition control center or SCADA control center, located northeast of San Bruno in San Francisco. On September 9th prior to the accident, PG&E personnel were working on an electrical distribution panel as part of a replacement project for the uninterrupted power supply unit or UPS, at the Milpitas Terminal.
During the course of the work at the Milpitas Terminal, the power supply modules for the pressure transmitters and other control devices malfunctioned. The electronic signal to the pressure-regulating valves, including one for Line 132, was lost causing the valves to move immediately from a partially opened position to a fully open position.
A pneumatically actuated valve designed to protect line 132 from over pressurization was automatically activated to control downstream line pressure at a pre-designated value. The line 132 pressure at Martin station showed a steady increase from 357 pounds per square inch (psi) to 386 psi over a 46 minute period before the line ruptured at 6:11 pm.
The control center in San Francisco registered a pressure drop at Martin station from 386 psi to 135 psi within 5 minutes of the rupture, generating a low pressure alarm on line 132. Within ten minutes after the pipeline rupture, two off duty PG&E employees reported the fire in San Bruno to the PG&E dispatch center in Concord, California.
The dispatch center dispatched an on-duty employee to investigate the reported explosion, approximately 12-minutes after the pipeline rupture; however, he was not qualified to operate mainline valves. PG&E dispatched a crew that was capable of isolating the pipeline about 30 minutes after the rupture.
PG&E crews manually closed the mainline valves upstream at Mile Point 38.49 and downstream at Mile Point 40.05, located less than 2 miles from each other. From the Transmission and Regulation Mechanic’s field notes we know that the upstream valve was closed at 7:30 pm, and the downstream valve was closed at 7:45 pm.
At about 7:42 pm flames at the rupture location had diminished to the point that firefighters were able to get closer to the ruptured pipeline.
This is a picture of the crater caused by the rupture of the pipeline. The crater was approximately 72 feet long and 26 feet wide. A 28-foot long section of pipe was ejected, and came to rest 100 feet south of the crater on Glenview Drive.
This is a photograph of the 28-foot ejected section of the ruptured pipeline. This section of pipe contained 4 of the 6 pups or short pipe spools, found in line 132 at the rupture location. Each pup was between 3.5 feet to 4 feet long and the NTSB materials laboratory report has identified variations in the material properties between them. There was no evidence of external or internal corrosion, or stress corrosion cracking on the examined sections. The NTSB materials laboratory examination determined that the rupture initiated along a seam weld in pup-1, as shown in the photograph.
The upper photo in this slide is a cross section of the pup 1 seam in the ruptured pipe near the point of origin. The appearance of the weld was consistent with fusion welding along the exterior pipe seam. On average, the weld penetrated 55% of the wall thickness along pup 1. By contrast the longitudinal joint seams at the north and south ends of the rupture were consistent with a typical double submerged arc weld (DSAW) with a full wall penetration as shown below.
In a 1956 realignment project, PG&E replaced approximately 1,851 feet of Line 132 that had been originally constructed in 1948. The section of the pipeline from north of Claremont drive and extending south to San Bruno Avenue was rerouted from the east side to the west side of Glenview Drive.
The pipe was identified in the PG&E Geographical Information System (GIS) database as nominal diameter 30-inches, seamless, Grade X-42 pipe. PG&E's specified maximum operating pressure (MOP) for the ruptured pipeline was 375 psi. According to PG&E, the maximum allowable operating pressure (MAOP) for the line was 400 psi.
In the Chairman's Opening Statement, she identified the issues areas for the hearing. I will now discuss some of these areas.
First, we will ask questions to get a better understanding of PG&E's operations. The ruptured segment of pipeline was isolated 1 hour 20 minutes after the rupture by off duty PG&E employees. We will be exploring some factors that contribute to typical PG&E control center response times during emergencies. Included will be a discussion of PG&E's policy regarding the use of Automatic Shutoff Valves and Remote Controlled Valves.
The PG&E Integrity Management Plan states: "the company shall consider the addition of Automatic Shut-off Valves or Remote Control Valves if they would be an efficient means of adding protection to a High Consequence Area." In 2006 a PG&E senior consulting gas engineer wrote a policy memo which concluded that Automatic Shutoff Valves and Remote Control Valves, as a Preventive and Mitigation measure, in a High Consequence area has little or no effect on increasing human safety or protecting properties.
The PG&E risk management program was developed to identify potential risks and mitigation measures to ensure the integrity of the pipeline. The factors that define this process and how the program was implemented on Line 132 will be explored.
Establishing an accurate maximum allowable operating pressure is critical to safe operations of a pipeline. The use of the GIS system and how maximum allowable pressure was established at 400 psi will be discussed.
PG&E's policies concerning operations, safety and rapid shutdown in high consequence areas also be looked at.
The PG&E gas control center is located in San Francisco. Here, the operators monitor and control the entire PG&E transmission network using supervisory control and data acquisition (SCADA). The SCADA system collects data from field instrumentation and displays this information to the gas system operator. Using this data, the gas operator can make changes to line pressures and valve positions in order to maintain the pipeline within established operating parameters.
SCADA will generate alarms based on the operating conditions of the line that the operators must address. The recognition of an abnormal event through SCADA trends and alarms are critical for an early detection of rupture and response. Operators rely heavily on the data collected and displayed over SCADA to make critical decisions about line operation.
The SCADA software prevents the operator from entering a pressure set point that exceeds the MOP of the pipeline. The operator can remotely operate some station valves to respond to emergencies.
PG&E's Gas Transmission Integrity Management Program is set forth in Risk Management Plan Six (RMP-06), which is one of the chapters concerning PG&E's risk management plan. Integrity Management is designed to provide methodology and procedures to ensure the safe operation of the gas transmission pipeline. PG&E's Integrity Management plan was first implemented in December of 2004.
The plan states PG&E will conduct an inventory of all the pipeline design attributes, operating conditions, and environmental threats such as structure, faults; to the structural integrity of its pipeline systems. PG&E uses a Geographical Information System as a database of pipe attributes such as type of seam, age, Maximum Allowable Operating Pressure, yield strength and determination of high consequence areas.
High Consequence Areas are defined using the Potential Impact Radius method, which designates a High Consequence Area by whether a calculated radius circle contains 20 or more dwellings. If it does, the area is classified a High Consequence Area regardless of class designation. The two factors used to calculate the Potential Impact Radius are pipe diameter and Maximum Allowable Operating Pressure.
Pipeline and Hazardous Materials Safety Administration (PHMSA) regulations require pipeline operators to develop and implement public awareness programs. These programs must follow the guidance in the American Petroleum Institute's Recommended Practice 1162. RP 1162 establishes guidelines for pipeline operators to develop, manage, and evaluate public awareness programs.
According to PG&E's public awareness program plan, the objective of the plan is to enhance public safety through increased public awareness and knowledge.
During this hearing, we will discuss the challenges of effectively conducting these programs.
As an intrastate gas transmission pipeline, Line 132 was regulated by the California Public Utilities Commission (CPUC). In 2005, the CPUC conducted an Integrity Management Audit of PG&E in which PHMSA participated. CPUC conducted a second integrity management audit of PG&E in 2010. There were no notices of violation cited in the 2010 CPUC audit letter.
Pipelines constructed before 1970 were not required by regulation to be pressure tested. This "Grandfather Clause" allows operators to continue operating natural gas pipelines at the highest pressure to which the pipeline had been subjected during the 5 years preceding July 1, 1970.
Additionally, we will be addressing the effectiveness of operator compliance in performance based integrity management regulations. We will focus on the requirements for self-assessment programs by the pipeline operators; and the approaches and policies of state and federal regulators in the exercise of their oversight responsibilities.
Inspection options that were available to PG&E for Line 132 were external corrosion direct assessment (ECDA), use of inline inspection (ILI), pressure testing or other technologies. Because of bends, valves and changes in diameter present in the pipeline, Line 132 was not easily amenable for inline inspection. PG&E opted for External Corrosion Direct Assessment technology on Line 132.
We are going to explore current technologies for inspecting and assessing the structural integrity of pipeline systems.
We intend to identify the capabilities and trade-offs associated with these technologies. We are also going to discuss new technologies that might be available to operators in the future.
The NTSB was notified of the accident about 8 pm on the night of the accident. A Go-Team consisting of eight NTSB staff members was launched early the next morning. I would like to acknowledge Vice-Chairman Hart, who was the Board Member on scene, and the NTSB investigators and staff who have supported the accident investigation and public hearing preparation.
Assisting Safety Board staff were parties to the investigation:
There were numerous state, local and federal agencies that were not parties to the investigation but played an important role in assisting the NTSB team with the on-scene portion of the investigation. Without their invaluable help, the on-scene process would have been significantly hampered.
Madam Chairman, this concludes my opening statement.
