June 2016, Vol. 243, No. 6

Features

Report Card: Has PG&E Passed the Test?

Santa Cruz, CA, population 62,864, is a coastal, university enclave situated 75 miles south of San Francisco on the northern edge Monterey Bay in the southern part Northern California.

A college town with a branch of the University of California and all the trappings, it also is the location for a corridor of one of Pacific Gas and Electric Co.’s (PG&E) major north-south, large-diameter natural gas transmission pipelines, not unlike one 50 miles to the north that ruptured causing a fatal explosion in September 2010 that carried sea changes still being felt nearly six years later.

San Francisco-based PG&E, one of the nation’s largest investor-owned utilities with 6,700 miles of high pressure transmission pipeline and 42,000 miles of distribution main, had to conduct critical safety pressure tests on segments of the line running through Santa Cruz in 2015 as part of an accelerated testing and replacement effort that the combination utility has been conducting the past five years in the wake of the San Bruno, CA tragedy that killed eight residents and injured scores more. The testing was to take several weeks, involving time-consuming, worker-intensive hydrostatic tests that are designed to detect and repair problems before they happen.

As is typical in the industry, the hydrostatically tested pipes had to be taken out of service, but natural gas distribution service throughout the community was uninterrupted and customers were mostly unaware of the safety work, ongoing for days.

About 46,500 local gas utility customers enjoyed uninterrupted service, according to Rob Morse, PG&E Central Coast Division senior manager. “It is these kinds of advanced safety projects that are helping use build the 21st century gas system our customers expect and deserve,” he said.

What Morse didn’t say is that PG&E employed an innovative use of mobile compressed natural gas (CNG) and liquefied natural gas (LNG) to supply the entire Santa Cruz community for the duration of the safety testing. It is a scenario that the giant utility is duplicating throughout its service territory since the post-San Bruno industry mandates have called for aggressive testing/replacement of gas transmission pipeline segments that traverse all of the nation’s major regions and population centers.

In this temporary supply process, the gas is trucked to an injection site in the form of CNG and LNG. In Santa Cruz the truck deliveries of gas were nearly constant, according to PG&E officials. Given the complexity of the Santa Cruz testing project, PG&E’s mobile CNG/LNG team tested the system for 48 hours prior to relying on the temporary supply sources. Five portable compressors, 32 tankers and three vaporizers operated by PG&E crews were deployed during the project.

In 2015, we supported 188 different outage projects with 439 individual taps supported,” said Jesus Soto, senior vice president for natural gas operations at PG&E, noting that the average volumes and times for the CNG/LNG temporary use vary widely. “We can support everything from a single customer to a single town.”

Although not fully appreciated by state regulators, elected officials or consumers, PG&E’s efforts in upgrading the integrity of its vast transmission/distribution pipeline system during the past five years are unprecedented by just about any measure. The experiential footprint and new chapters written for industry benchmarking purposes have national implications, according to Soto, a veteran with many years at El Paso Pipeline Co. He joined another gas industry veteran, Nick Stavropoulos, now president of the PG&E gas system, in 2012 to lead an organization that was staggered by the aftermath of San Bruno.

“We put people and safety at the heart of everything we do. We are committed to investing in reliability, quality and the integrity of our gas system, and we’re also committed to continually improving our effectiveness and affordability of our processes,” said Soto, outlining PG&E’s three-pronged strategy, which he and Stavropoulos helped develop.

Soto ticked off PG&E’s completion as of February 2016 of 11 of 12 recommendations by the National Transportation Safety Board (NTSB) in 2011. A major focus for PG&E for reducing damages to its 6,750 miles of transmission and 42,000 miles of distribution pipe has required making the system more “piggable,” moving away from reliance on external measures to internal ones for scanning pipe with varying diameters. While it is making progress, Soto acknowledges that nationally his company still has a ways to go to get in the top quartile for fewest “dig-ins” damaging its system.

“When I look at the damage ratios across the country, I have seen them categorized by state, and PG&E’s performance now [February 2016] would be in the top 10 in the country,” he said. “There are areas now where we are setting the benchmark for other operating companies in the amount of asset modernization we are doing, getting rid of cast iron pipe and upgrading leak management. So there are many elements of how we run our business that now set the benchmark for others.”

In March, Soto accepted the highest honor at the 2016 Common Ground Alliance’s Excavation Safety Conference at which PG&E was cited for its “overall leadership” in damage prevention. The award is given annually to an organization that has shown “leadership and innovation” in supporting prevention of damage to pipelines, the CGA said in presenting the award. (While PG&E’s dig-ins dropped by 13% in 2015 from the previous year, it had 1,900 dig-ins during the year, the vast majority to its distribution lines, but there were two incidents involving the transmission pipelines that resulted in single deaths in each case, and each were caused by third-party contractors who violated state laws.)

While PG&E invested heavily in time, money and work force to complete maximum allowable operating pressure (MAOP) testing and GPS surveying of its entire transmission system over the years since San Bruno, the return for similar investments in recordkeeping have yet to fully pay off. Regulators in early 2016 were still looking at substantial fines and penalties for recordkeeping snafus that the utility has encountered since the San Bruno disaster.

Soto and the utility’s other brass strongly disagree with conclusions reached so far by the California Public Utilities Commission’s (CPUC) safety division calling for a more than $100 million fine for alleged failures leading up to multiple distribution pipeline incidents spread over a number of years. CPUC safety staff called the utility recordkeeping “deeply flawed,” but PG&E claims the regulatory staff has misinterpreted applicable regulations and the record in the then-ongoing regulatory proceeding acknowledged the existence of improvements that PG&E has made.

In talking to P&GJ, Soto chose to emphasize major successes that have been made in transmission system recordkeeping, downplaying the distribution side because of the ongoing CPUC case. Generally, PG&E is focused on “perfecting” its records, he said, noting that “when we find gaps [between records and actual infrastructure] we will address those.”

A crown jewel for PG&E’s efforts on its transmission system is the $80 million spent completing a centerline survey of all 6,750 miles that spans from the California borders with Arizona and Oregon to the heart of its service territory throughout Northern California. It involved hiring and deploying more than 30 survey crews for more than a year starting in 2013 to complete a sophisticated geospatial survey. The crews used survey- and mapping-grade geospatial positioning system (GPS) devices working on the ground on foot. They traversed residential, commercial, industrial and agricultural properties, locating, marking and acquiring GPS coordinates for the center of the pipeline, assessing the immediate zone of 10 feet on each side of the pipe.

As a result of those concentrated boots on the ground and some high-level internal executive leadership, PG&E points to having more precise pipeline mapping, allowing it to better serve its millions of retail gas utility customers. In addition, the often much-maligned giant utility now can boast it has enhanced ongoing pipeline safety while working more effectively and efficiently with first-responders, which most of its critics said the company was unable to do when the San Bruno incident occurred.

“I am not aware of any other operator in the country that has taken the approach of doing a complete centerline system survey for a legacy system,” said Soto, expressing obvious pride in PG&E’s accomplishment. “We consolidated more than 4 million records related to the transmission system and more than 12 million pages on our distribution system into electronic data that can be accessed from anywhere.”

Leak detection is another area in which PG&E has withstood lots of criticism but for which it claims to have made great strides with its embracing of a Silicon Valley-inspired technology from Picarro. It is an avid supporter of technology that the venerable more than a century-old utility might have shied away from in its gas utility operations before San Bruno. Soto sees PG&E making headway in the leak detection area beyond what any other utility is doing at the beginning of 2016.

“We were the first to use Picarro and that equipment is a thousand times more sensitive than traditional leak detectors,” Soto said. The technology likely is going to be used on 70% or more of the PG&E system this year, he said, noting he knows of no other utility using the technology on as large a percentage of their systems as PG&E has committed to do.

“We know that the technology works,” he said. “Given all that we have done, I think our asset modernization program is the most extensive in the country.”

Simply put, Soto claimed the equipment has found 80% more leaks than PG&E’s traditional leak detection programs. “We’re very committed to repairing these leaks as we find them and not letting our leak backlog grow,” he said, adding that the company goal is to have no more than 100 nonhazardous leaks in the utility backlog at the end each calendar year. “We’re probably the best in the country among operators of our size in managing nonhazardous leaks.”

Soto pointed out that today when one of PG&E’s 4.3 million gas utility customers call with a gas odor complaint, a field service person is at their door within 20 minutes on average. In 2015, the company responded to 113,000 odor complaints. These are separate from leak reports from the streets; they emanate from individual customer homes and businesses. Each morning at 7:30, PG&E conducts an operations call companywide, reviewing the past day’s performance and the work for the new day.

“We analyze where crews may need help, and we look at how our past day’s performance was on odor calls,” Soto said. “The volume and response rates get reviewed daily [to determine how fast on average the utility is responding from day to day].”

In 2013, PG&E evaluated its entire transmission pipeline system, one of the largest in the nation, and established a long-term plan for maximizing piggability. Last year, it updated that plan to take into consideration the advancements in in-line inspection (ILI) tool technology. Since 2014, the utility has been engaged in what it calls “a very aggressive” attempt to “make piggable” more of its transmission pipelines.

The current goal is to increase today’s 1,590 miles of piggable transmission pipe to 4,465 miles, or 67% of the system, by 2024.

“Additionally, PG&E is working with several ILI tool vendors to develop custom low-pressure tools, which will allow PG&E to inspect even more transmission pipelines using ILI once these tools are commercially available,” a PG&E spokesperson said.

The ongoing technology advances employed, including in-line inspection tools, are what PG&E considers its “roadmap” for becoming the safest, most reliable gas utility in the nation, Soto said. “We’re focused on technology and how we perform in areas such as leak management. We’re very focused on technology to make our system piggable.”

Technology also can help PG&E leverage all of the various data it collects electronically every day on its system. This deals with what Soto calls “situational awareness” and “situational intelligence” to create more situational analytics for deploying people and equipment resources.

PG&E is working with two of the largest inline inspection providers in the world – ROSEN and GE Oil & Gas (GE/PII) – to develop advanced inspection tools to operate in multi-pipeline dimension systems. In addition, PG&E works on a collaborative research and development (R&D) basis with the Pipeline Research Council International (PRCI), NySearch, and Gas Technology Institute.

If PG&E is to fulfill the last of the 12 NTSB recommendations – verifying the integrity or replacing 1,000 miles of transmission pipeline in populated areas – meeting the increased piggability of the system is crucial, noted Soto, emphasizing that the utility has shifted its focus of its integrity management program from traditional external corrosion management programs to more inline inspections as its primary method of assessment.

By the end of 2016, PG&E expects to have all of the 1,000 miles of transmission pipe in populated areas tested. Remaining will be areas where very short segments will be tested. In some cases, PG&E will just replace those pieces. It will take a few more years to complete the remaining 1%, but “after this year, we are essentially complete with 99.9% of the NTSB recommendation,” Soto said.

In addition, PG&E has the ongoing task of replacing more mainline valves with automatic shutoff equipment, Soto said. On the distribution side, it also is replacing main at a greater rate, hitting 102 miles of distribution pipe replacement in 2015, compared to 27 miles in 2010.

In distribution, PG&E plans to increase the numbers of miles of pipe replaced annually, and apply the Picarro technology more widely, pushing it to as much of the system as it can. In the process, Soto noted that it intends to increase the visibility of its supervisory control and data acquisition (SCADA) system, installing extensive remote terminal unit (RTU) devices all across the system.

The RTU devices being installed to increase SCADA visibility include both the standard RTUs and electronic recorders equipped to provide remote telemetry, Soto said. In this regard, PG&E uses a variety of communications mechanisms to use the RTUs, including radio frequency.

Soto and the PG&E gas team have no illusions about their challenges in reshaping the natural gas part of the utility being easy or cheap. He said they view their work as never being done, and they are mindful they need to spend billions of dollars in the long term to “make our system safer while keeping in focus the potential strain on our customer rates. Customers demand safety, but they want us to spend the money prudently,” he said.

He also acknowledged that replacing pipe in California for various reasons, such as population density, permitting and environmental regulations, is costlier than other areas of the nation. PG&E is prioritizing the replacement of transmission pipe within urban areas, leading to more subsurface utility crossings, traffic control and other issues that add to the cost, a PG&E spokesperson said. “We’re committed to adhering to California’s strong environmental protections and this can lead to longer permitting timelines and alternative construction methods,” he said.

When asked about the results and third-party verification that overall PG&E’s gas system is on the right track to becoming a national model, Soto points to the international certification obtained in the past 18 months by his company. He claims no other U.S. utility or pipeline operator has achieved all three certifications for asset management, review and certification. PG&E is one of the first utilities in the world to hold both the International Organization for Standardization (ISO) 55001: 2014 and Publicly Available Specification (PAS) 55-1: 2008 certifications.

Two years ago (2014), Lloyd’s Register (LR), a global engineering, technical and business services organization, traveled throughout PG&E’s 70,000-square-mile service area, reviewing safety practices, information and risk management policies, along with employee qualifications, emergency response protocols and another 20 critical areas of asset management. The international certification process also involved what PG&E called a series of “rigorous, independent audits and interviews” of over 150 PG&E management, field employees and contractors.

As of early 2016, PG&E also had met the new American Petroleum Institute (API) RP 1173 standards, which Soto described as “creating a learning environment, including 10 elements in it for recommended practices, such as risk management, emergency response, operating standards, training and documentation. “It is focused on continuous improvement of pipeline safety and integrity,” he said.

When Soto is reciting the list of the accomplishments of PG&E, despite continuing critics among consumer groups, regulators and elected officials, he prefaces his remarks with a “I-am-very-proud-of…” His voice trails off, and with that introduction, he launches into another real-life tale of people and enhanced technology getting the job done.

Meeting the Challenges

An icon for PG&E’s turnaround is its state-of-the-art Gas Control Center located in an East San Francisco Bay suburb, and Senior Vice President Jesus Soto points to it as demonstrating the company’s enhanced safety and reliability in its gas operations. In fall 2015, the control center under the leadership of Manager Andy Wenzel and Supervisor Robert Quijalvo and their team isolated and shut down a 34-inch, 750-psi transmission pipeline in the energy-agricultural central valley near Bakersfield, CA, in 14 minutes after a bulldozer cut into the pipeline.

From the time of the first alarm at gas control, gas system operators, Michael Valenti and Keith Boydstun validated the alarms, pinpointed where it was on the system, acknowledged that there was a loss of containment, reviewed the isolation plan and closed the first valve within four minutes, Soto recalled. Then, Marc Ceniceros, senior system coordinator, and another coordinator, Kie Fujimoto, closed the other valves to create a full isolation, taking no more than 10 minutes.

“To me, this was textbook; that’s what our people get trained on and it is a great example of a controller being able to acknowledge an alarm, review the isolation plan, start the isolation without having to get approvals from his leadership or senior management,” said Soto, brimming with obvious pride in how those controllers on that shift that day responded. “They see hundreds or thousands of alarms throughout their careers, but may not deal with an actual loss of containment.”

For Soto, in addition to the human side, the incident was an example of how PG&E is beginning to “leverage” all of its infrastructure added since San Bruno and the stepped-up training to sharpen the decision-making skills of its gas controllers. “This validates how advanced our emergency preparedness is,” Soto said.

Commissioned in 2013, the control center also proved its worth on a Sunday, Aug. 24, 2014 when a 6.0 earthquake hit in California’s famed wine country in Napa County. The gas center proved to be a key element in the speed and effectiveness of the utility’s response under challenging conditions.

“We never lost containment of the system or the visibility of our SCADA systems,” Soto said. PG&E quickly reduced pressure on the system in Napa-Sonoma counties, mobilizing the utility team’s response, restoring service and pinpointing calls and locations of concerns.

“All of this was done within hours,” Soto remembered. “We very quickly began surveying hundreds of miles of our distribution system, and over 11,000 services, and within days put out a notice to all of our customers in the wine country to tell them to request a gas safety check if they wanted it.”

This involved more leveraging of the control center’s technology. Soto said the center literally provided the intelligence and broad views of the pipeline system that were crucial to deployment of the recovery effort.

“We could superimpose seismic models with our GIS layers of our system to analyze where we proactively should lower the pressure in our system until we were able to complete the appropriate surveys and integrity checks,” he said. “We were able to combine intelligence, data and decision-making within hours of a significant event.”

Richard Nemec is P&GJ’s West Coast correspondent. He can be reached at nemec@ca.rr.com.