The energy pipeline industry works 24/7 to avoid “wake-up calls,” but when one comes, there is an obligation recognized by all segments to answer or find answers. That situation was no different in the wake of September’s natural gas transmission pipeline rupture in the San Francisco suburb of San Bruno.
While the National Transportation Safety Board (NTSB) and the California Public Utilities Commission (CPUC) are conducting their own investigations, as is the pipeline operator, Pacific Gas & Electric Co. (PG&E), all of the industry is searching for assurances the tragedy that killed eight people and destroyed or damaged more than 50 homes will not happen again.
Kirk Johnson, PG&E’s vice president for gas engineering and operations, felt “a personal sense of responsibility to help” as soon as he learned of the San Bruno pipeline explosion and fire. Employees of the San Francisco-based combination utility, one of the biggest in the nation, responded “without having to be asked,” Johnson said, giving blood, donating clothing and volunteering in San Bruno.
Throughout the aftermath, while responding to second-guessing and legitimate questions alike from regulators and the general public, PG&E has stepped up communications with all of its local communities to assure government officials and residents about the location and safety of the utility’s 6,700-mile transmission pipeline system.
In the fall, the federal Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) issued an advisory bulletin to operators of gas and hazardous liquid pipelines reminding them that federal law requires operators to share their written emergency response plans with local emergency responders. Operators were warned that in future compliance inspections PHMSA intends to evaluate the extent to which operators share their emergency plans.
Industry legal and regulatory counselors are predicting this enforcement effort likely will remain strong in the months ahead as 2010 became the deadliest in six years for pipeline fatalities with the tragedy at San Bruno, according to PHMSA data released late last year (nine fatalities and 58 injuries this past year, compared to an average of one fatality and five injuries annually from 2005 through 2009).
Noting the company was taking a $238 million charge against third-quarter 2010 results, PG&E Corp. CEO Peter Darbee said the utility’s focus since San Bruno has been three-pronged. “First, providing assistance and support to the people affected; second, taking appropriate steps to assure that our gas system is safe; and finally, learning what led to this tragedy so that we and the industry can prevent something like this from ever happening again.”
It is the current learning phase – centered on the NTSB’s ongoing investigation into the cause – that remains long and arduous for everyone in the industry. And in the meantime there are new interstate pipelines to build and tens of thousands of miles of existing pipelines to operate safely and efficiently.
Large, long-time operators such as TransCanada carry out extensive pipeline integrity and maintenance programs, employing extensive geospatial systems. “We know all the specifics of our pipe as part of our integrity management program,” said Calgary-based TransCanada media relations representative Terry Cunha, who adds that the pipeline operator keeps close track of the locations, manufacturers, coatings, construction year and maintenance history of every piece of pipe in its system.
TransCanada touts its efforts for advancing new technologies deployed on gas pipeline systems, and Cunha says the company has been “instrumental in the development of newer steels, higher strength steels, quality coating systems and enhancement of maintenance tools.” The company is convinced pipelines are the safest way to move oil and gas.
In a post-mortem that focuses on small pipeline segments measured in hundreds of feet, not miles, PG&E’s Johnson made clear that the combination utility intends to help the industry and its own operations to advance inspection approaches and improve industry and individual utility best practices.
(PG&E has no involvement in the San Bruno pipe segments from the immediate impact area; all of them were taken by the NTSB for analysis as part of its ongoing investigation, along with some other samples in addition to the exposed ends at the blast site that PG&E has been working on since the Sept. 9 rupture and fire.)
Noting historic statistics pointing to strong safety standards and results over the years, Donald Santa, president of the Interstate Natural Gas Association of America (INGAA), told a congressional subcommittee hearing in the immediate aftermath of San Bruno that the tragic rupture underscored the need for “high levels” of pipeline safety practices and that INGAA is committed to helping policymakers and regulators find “effective, well-founded solutions.”
Santa stressed that INGAA feels the 2002 Pipeline Safety Improvement Act is working and the national pipeline integrity management program is three-quarters of the way through a 10-year effort.
A logical reaction related to the integrity program and the fact that PG&E had made various inspections of the failed pipeline segments in recent years is to question whether the San Bruno incident is an indicator that the national integrity program needs updating. Santa urged that the industry and public refrain from “drawing any conclusions about changing the integrity management program” until after the NTSB’s investigation is complete, the causes are identified and a full analysis of those causes is completed.
Similarly, the American Gas Association’s (AGA) Chief Operating Officer Lori Traweek cautioned against the urge on the part of public policymakers to speculate on San Bruno’s causes. Said Traweek, “ultimately, when the cause(s) are clearly identified, stakeholders will be able to determine if the tragedy was “an isolated incident or has broader implications.”
Acknowledging that the cause of the San Bruno rupture may remain unknown for most of 2011, PG&E’s Johnson said as soon as the NTSB’s final determination is made PG&E intends to “roll it into our other programs, but until then we are taking our first steps through a new 2020 pipeline program,” which he referred to as a “dialogue” with the industry, regulators and communities. It was crafted within a couple of weeks of San Bruno.
Gas Odors, Construction Work
In the initial days and weeks after the rupture, reports swirled concerning residents in the area calling to report gas odors, utility crews being spotted in the immediate area and municipal contract crews doing sewer work excavations in the area near the section of the pipeline that ruptured. Upon a checking of the records and verifying work the City of San Bruno had done, none of the reports were accurate. There were only two calls to PG&E regarding gas odors from July 1 through the date of the incident and only one proved to be an actual leak (at a residential meter that was repaired at the time).
There was also conjecture on pipeline pressure and whether an electronic glitch at a utility pipeline control center 60 miles to the southeast may have caused a surge in pressure in the fatal pipeline (Line 132). Federal limits on a pipeline like this in a high consequence area (HCA) are set at 400 psig (pounds-per-square-inch-gauge); PG&E’s own operating limit was 375 psig, and, since the rupture, all three lines in the area (101, 109 and 132) have been operating at 300 psig as they were going into the peak winter load season at year-end 2010.
PG&E’s transmission pipeline system includes hundreds of over-pressure control valves, installed where appropriate to protect pipelines from exceeding their maximum pressure design limits. Gas supplies are fed northerly through Line 132 and the other two transmission lines on the peninsula, traveling from Milpitas in the far southeast part of the San Francisco Bay and originating from one of four sources – local storage in Northern California, or supply basins in Canada, the Rockies and the Southwest.
According to the NTSB’s preliminary report last October, the deadly blast released 47.6 MMcf of gas, and the ruptured pipeline was fractured length-wise and at welds that held the pipe sections together. There was no mention of corrosion, however. The thickness of the pipe’s walls was described in the report as “fairly uniform.”
Sept. 9, 2010 San Bruno, CA, Gas Pipeline Rupture
One of three major natural gas transmission pipelines running north-south on the peninsula between San Jose and San Francisco – the 30-inch PG&E Line 132 – ruptured on Sept. 9, 2010, causing an explosion and fire during the dinner hour in a quiet residential neighborhood about 10 miles south of the San Francisco-San Mateo County line, killing eight people, injuring dozens more, destroying 37 homes and damaging dozens more homes.
The pipelines involved were originally built in 1948 and segments now in question were relocated and rebuilt to accommodate new housing development in 1956. The NTSB and CPUC were on the scene in San Bruno within 24 hours. PG&E records indicated Line 132 was inspected in each of the three previous years—2008 through 2010.
Line 132 underwent aerial pipeline inspections six times between March 2009 and June 2010; leak surveys performed by PG&E, including the rupture location for Line 132, were done in May 2008, March 2009 and March 2010. In 2009, PG&E performed a direct assessment of Line 132 as part of the baseline assessment of the line required by federal pipeline safety regulations, using an “external corrosion direct assessment (ECDA) process, a four-step process that included the segment involved in the Sept. 9 rupture.
Gas flow to Line 132 could not be stopped remotely, and thus it took more than 90 minutes after the explosion to stop the transmission gas flow on the 30-inch pipeline; a PG&E crew was dispatched within minutes to isolate the ruptured pipe. This required the manual closing of the nearest mainline valves. Upstream (MP 38.49) and downstream (MP40.05) valves were closed at 7:20 p.m. and 7:40 p.m., respectively, and the incident occurred a few minutes after 6 p.m.
It wasn’t until later in the evening that PG&E isolated its natural gas distribution system serving the San Bruno residences in the area and within a minute of stopping those flows at 11:30 p.m. that fires at all of the damaged homes were extinguished.
Federal statistics, which may lag those of the individual California utilities, indicated the state has 12,414 miles of gas transmission pipelines, with PG&E and Sempra Energy’s two utilities (Southern California Gas Co. and San Diego Gas and Electric Co.) accounting for nearly 10,000 miles of that total. There are 102,475 miles of distribution lines, nearly 90,000 miles accounted for by the three utilities.
In the lead-up to the explosion, NTSB investigators found that when a PG&E crew was working on an uninterruptible power supply (UPS), the gas pipeline’s computer control system malfunctioned. Electrical power to the system dropped, which caused the control valve to open and pressure to build in the pipeline.
The report said “instead of supplying a predetermined output of 24 volts of direct current, the UPS system supplied approximately 7 volts or less to the SCADA (supervisory control and data acquisition) system. Because of this anomaly, the electronic signal to the regulating valve for Line 132 was lost. The loss of the electrical signal resulted in the regulating valve moving from partially open to the full open position as designed.”
Pressure in the pipeline following the malfunction increased to 386 psi, and a pneumatically activated valve maintained the pressure at that level, the NTSB report stated. At about 5:45 p.m., the system was recording a pressure of more than 375 psi at another station in Daly City, CA, north of San Bruno. The pressure continued rising until it reached about 390 psi at around 6 p.m., said investigators.
Eight minutes later pressure dropped to 386 psi, and at 6:11 p.m., when the San Bruno explosion occurred, pipeline pressure had fallen to 361.4 psi. A minute later pressure stood at 289.9 psi.
An investigation is continuing concerning fractures in the pipeline and the pipe’s metal strength, the NTSB said. An electron microscope analysis of the ruptured pipe segment also is being conducted as part of the long-term NTSB investigation.
News Media Speculation
At one point, local news media surfaced the possibility of “microbiologically influenced corrosion” (MIC). PG&E said that it had found one possible case in the past five years that showed it could have involved MIC. That leak occurred in a period during which the utility experienced three transmission pipeline leaks.
The utility did not say in what part of its system the potential MIC internal corrosion could have taken place, nor would it confirm that MIC was automatically one of the potential causes that NTSB would analyze. “We really cannot speak to NTSB’s investigation,” Johnson said.
The world’s largest pipeline research facility, and described as the only one of its kind in the nation, is at Ohio University in Athens, OH. It maintains an institute studying corrosion and what it calls multiphase technology that looks closely at MIC. The MIC research group has developed a mechanistic model for understanding how these micro-organisms over time can compromise pipelines.
Another predictable part of the San Bruno aftermath was the reaction of federal and state legislators and the CPUC initially indicating that stepped-up oversight was needed for the state’s high-pressure gas pipeline system with PG&E’s ongoing operations being the focal point. Johnson and other PG&E senior executives understandably are very deferential to both regulators and elected officials.
The new Congress is scheduled to review reauthorization of the 2006 pipeline safety act, and now it is expected to shine a brighter spotlight on its proceedings in the wake of San Bruno. The PG&E incident drew congressional information hearings within a few weeks of the explosion. Representatives including the congresswoman representing the San Bruno area, Jackie Speier, proposed new laws on safety and the public notification of pipeline locations.
“I would argue for greater scrutiny by the CPUC,” said state Sen. Mark Leno, public safety committee chairman, speaking at a state hearing in October. “That is really something that the Legislature (going forward) can be a part of. The issue of safety and maintenance programs does not go away as we await the final conclusions of the NTSB’s investigation.
“While that (federal investigative) process is unfolding, I would encourage CPUC and staff to consider beginning a formal investigation of its own. (It did just that.) There should be a full, public, transparent investigation that would address both the governmental and community concerns. This is just the beginning of the conversation and not the end,” said Leno.
In concluding the state legislative joint hearing, state Sen. Alex Padilla, chair of the energy/utilities committee, said there may be “a need to tighten those (regulatory) processes and perhaps provide less flexibility for utilities to shift money from one project to another,” referring to pipeline maintenance/repair monies approved for one set of projects and then shifted to others as priorities are changed by the utility.
“There is a need for the CPUC to keep a closer eye on projects that are funded to make sure they
are actually undertaken and completed on a timely basis.” He said shut-off valves and the mapping and identification of pipeline locations are two other areas that need more attention in the future.
Padilla made it clear the California Legislature would be studying these and other issues “all with the intended purpose of making pipeline infrastructure in the state safer and minimizing the chances of another incident like San Bruno ever happening again.”
Utility Operations Dissected
In response to CPUC orders during the first month after the pipeline rupture, PG&E completed detailed assessments of the existing transmission pipeline segments in San Bruno; completed an initial assessment and began a longer-term, third-party study of retrofitting automatic valves on portions of its pipeline system; completed an accelerated pipeline survey of its entire high-pressure transmission backbone system; and began curtailment plans for San Francisco and the peninsula this winter in the event of continued reduced operating pressures (300 psi) on the three lines running up the peninsula.
At the time of this writing, PG&E and the CPUC appeared to be in agreement with the scope and direction of these simultaneous efforts by the utility. They were summarized for state regulators in an Oct. 25 filing by PG&E to the regulatory commission’s Executive Director Paul Clanon.
In and around San Bruno the utility surveyed nearly 16 miles of transmission pipeline with segments going through 26 HCA areas, along with distribution feeder mains. The survey did not identify any “integrity issues” requiring immediate repair, the utility told the CPUC.
Although there are no specific regulatory mandates on the use of automated valves, PG&E’s initial assessments concluded that retrofitting some of these devices on its transmission lines should be considered, and it has identified up to 300 potential locations on pipeline segments representing nearly 600 miles collectively. To fully assess the job and study what should be recommended in this area, PG&E will be hiring a consulting firm to complete a report by mid-year 2011.
Two types of valves are being considered – automated remotely controlled devices allowing a main pipeline valve to be opened and closed at a remote operations center – and automatic line rupture shutoff valves that close when they detect a line rupture from falling pressure or increasing gas flow rates. The utility is considering one of these types of valves on various parts of 565 miles of pipeline segments it identified in HCAs.
The utility’s accelerated aerial and ground survey covered 2,500 miles of Class 3 and 4 pipes operating above 60 psi, and HCA transmission mains in Class 1 and 2 locations, resulting in what PG&E categorized as four “Grade 1 leaks.” None of the problems – all of which were repaired – occurred in the San Francisco or peninsula areas affected by the rupture.
In addition, PG&E reported that it “identified and immediately repaired 34 other Grade 1 leaks on distribution lines, distribution feeder mains operating above 60 psi, or other equipment attached to these operating pipelines.” In most cases, the repairs just involved tightening fittings, greasing parts, patching welds and replacing regulators.
Regarding the CPUC-mandated lowering of operating pressures on the three transmission pipelines feeding San Francisco from the peninsula, PG&E reported that in extreme cold situations all or part of its noncore customers on the peninsula and in San Francisco would be curtailed this winter, unless some upward adjustments in pressure are made on one or all of three transmission lines, including the ruptured Line 132 in part of San Bruno.
PG&E spent much of the past fall in one-on-one contacts with its noncore customers, helping them plan for curtailment situations. By the start of December, PG&E had briefed all of these customers on what was likely to unfold this winter. One positive development was the fact that a lone remaining natural gas-fired power plant in San Francisco operated by a unit of Mirant Corp. accounted for nearly 60% of San Francisco’s interruptible gas load, and it was not going to be needed for electricity reliability because of a new submarine transmission cable at the bottom of San Francisco Bay that would begin feeding the city this winter.
With the power plant curtailment and some other modifications in the lower pressures on the three transmission lines, PG&E was hoping to avoid the need for cutting off industrial load on the peninsula. Fingers were crossed, however, with every new long-term weather forecast.
Richard Nemec is based in Los Angeles and serves as West Coast Correspondent for P&GJ. He can be reach at: email@example.com.
New Ruby Pipeline Is Laboratory For Latest Safeguards
As the shattered pieces of the San Bruno rupture are deconstructed at all levels, a current “laboratory” for building in the most advanced safeguards in a major interstate natural gas transmission pipeline emerges with El Paso Corp.’s Ruby Pipeline project now under construction. Ruby is a $3 billion-plus, 680-mile, 1.5 Bcf/d, 42-inch pipeline with an in-service target date of June 2011. Nearly half of the route (44%) parallels road and utility rights-of-way between Opal, WY and Malin, OR.
There will be 44 block valves with actuators, four compressor stations, and total control of the new pipeline from El Paso’s Colorado Springs, CO gas control center, one of three such centers maintained around the clock, 365 days a year (the others are in Houston and Birmingham, AL controlling separate El Paso pipelines).
When Ruby begins commercial operations, El Paso officials emphasize it will immediately become part of their companywide operations, maintenance and pipeline integrity program. The enhanced pipeline integrity program has been in effect since the aftermath of El Paso Natural Gas Co.’s own major pipeline explosion (Line 1103) that resulted in 12 deaths near Carlsbad, NM in 2000.
For the Carlsbad rupture, the NTSB final report found that “severe corrosion damage,” which reduced the wall thickness of the pipe segment involved, was a major cause.
Post-Carlsbad, the 2002 Pipeline Safety Improvement Act prescribed stepped up pipeline inspection and oversight procedures for the industry. El Paso’s integrity program exceeds the minimum federal standards, according to the company.
Ruby’s valve actuators – 42 on the main pipeline and two on the lateral that interconnects with TransCanada’s GTN pipeline in Oregon – will be controlled from Colorado Springs. The compressor stations will have a “full complement” of safety devices designed to shut the stations down as soon as something goes wrong – high equipment vibrations, hazardous gases, fire, etc., according to an El Paso spokesperson. There also will be over-pressure protection. Ruby’s maximum allowable operating pressure (MAOP) will be 1,440 psig and the system will prevent the compressor stations from pumping the pressures above the MAOP.
Similar to El Paso’s other cathodically protected and continually inspected pipelines, there also will be sophisticated telemetry and electronic systems monitoring the Ruby pipeline 24/7 year-round. Operators in the gas control centers can see real time the line flows and other key data via telemetry and take corrective actions, if necessary.
When operational, Ruby will become part of El Paso’s portfolio, the nation’s largest interstate gas pipeline system. El Paso operates more than 37,000 miles of pipe, most of which are 6-inch diameter or larger, located onshore, and are in the company’s inline inspection (ILI) program. At the end of 2010, up to 92% of these six-inch-or-larger diameter pipelines had been inspected and the company says it is on track to complete the program by 2012. About 3% of the total system, or 1,000 miles of pipe, is classified as being in high consequence areas (HCA), which is what San Bruno was.
For Ruby, about 55% of the route runs over public land, mostly BLM, U.S. Forest Service, etc. The rest runs over private land. “Ruby’s remoteness is helpful in a way because the pipeline route avoids densely populated areas,” the spokesperson says.
With the latest technologies, what is being built into Ruby’s safety systems will further enhance existing safety systems found in the rest of the El Paso’s system, the pipeline operator says.
“While the vintage of pipe and related systems vary (greatly), based on technologies and equipment available at the time of original installation, El Paso has made improvements to compression and related facilities, and pipelines have been upgraded, repaired or replaced where needed through the ongoing operations, maintenance and integrity program,” said spokesperson Richard Wheatley. “Some of our systems have been in place for 50 or more years.”
He hastens to add, however, that an often misleading aspect of pipeline incidents, such as with San Bruno, is that the news media reports and the general public often misunderstands the age issue and incorrectly equates it with higher operating risk.
Age alone doesn’t mean a pipe is necessarily unsafe, vulnerable to problems or needs replacement, Wheatley maintains. “A lot of the news media coverage misinterprets the age issue. We have had no failures on our pipeline systems where age by itself was the cause of a failure,” he says. “There is no data from an industry perspective to indicate that the properties of steel are reduced as a direct result of a pipeline’s age. Proper inspections and maintenance are essential.”