“It is encouraging to see that innovations are occurring in the (gas pipeline) public safety space…” –Timothy Alan Simon, Commissioner, California Public Utilities Commission, and Chair, NARUC Natural Gas Committee
While no one would ever label the natural gas pipeline industry as “high-tech,” technology nevertheless is playing a major part in the industry’s response to a series of deadly pipeline incidents in North America in the past 18 months. For example, today there can be a digital footprint created and stored on new pipe literally as it is being buried in the ground.
Panels of experts told federal regulators earlier this year that the goal is to identify all of the threats that can lurk in and around a given pipeline. Then, pipeline operators need to understand clearly what they are and what they mean, so steps can be taken to mitigate, if not totally eliminate, them.
In April U.S. Transportation Secretary Ray LaHood hosted a pipeline safety forum with the express purpose of “reducing pipeline risks and preventing accidents,” and it focused on a half-dozen areas needing increased attention to accomplish that. One of those areas is the research/development (R&D) needed for technology advances. It was noted that the tools can be upgraded through various national efforts, but the implementation must come in stringent pipeline-by-pipeline integrity management efforts, many of the forum participants stressed.
At the LaHood forum, Questar Pipeline Co. CEO Allan Bradley, chairman of the Interstate Natural Gas Association of America (INGAA), addressed technology as one of four areas the industry is focusing on. Bradley was candid and realistic in his assessment, owning up to the fact that the pipeline industry’s R&D efforts have been perceived as what he called “anemic.”
“I believe that our R&D efforts are so widely distributed across out industry that they go unnoticed,” Bradley told the forum in Washington, DC on April 18. “In response, I recommend that the industry, research organizations and government create a pipeline safety technology road map that identifies and prioritizes our research needs.”
Along with stepping up the amount of collaboration and sharing of lessons learned throughout the industry, Bradley urged more investment in what he called “technology that can reduce risk.” He cited the example of new inline inspection (ILI) tools, or “smarter pigs,” that can detect loss of metal in pipeline walls caused by construction flaws or corrosion.
At a National Transportation Safety Board (NTSB) set of hearings in Washington, DC last March, an inline pipe inspection expert from General Electric, Geoff Foreman, called inline inspections “fundamental” to any pipeline integrity work. And he added that it is still a process that requires both a “clean pipe” and a clear focus on choosing the right ILI tool to expose a specific risk. An ILI tool good for detecting cracks is not the one needed for uncovering corrosion, Foreman told the NTSB gathering (March 1-3).
“There is no single pipeline tool that can identify every type of threat,” Foreman said. “To achieve the greatest level of confidence,” he advises multiple ILI tools be used.
In many cases the technologies being applied are not new, but they now include refinements that have been developed through painstaking research. Foreman cites as an example the improved ability to detect cracks in gas pipelines from naturally occurring curves associated with the manufacturing processes. He told NTSB members that it is “vitally important” to also improve the ability to determine the sizes of cracks that are uncovered.
Among the key conditions in integrity programs for pipelines are such things as pressure, flow and fittings. There is no single solution or technology for dealing with these variables, according to Foreman, who is GE’s ILI pipeline expert.
Pipeline engineers in Canada and the United States have been tracking and writing about ILI as part of integrity management systems for several decades. Advances have been made on a variety of ILI tools, as outlined in a presentation this spring at the 6th Pipeline Technology Conference 2011 in Hannover Messe, Germany.
A notable example at that conference was magnetic flux leakage technology (MFL) developed to better detect, locate and size metal corrosion. While MFL has been around for years, most recently technology and innovation have vastly improved the MFL tools’ capabilities, according to Frank Sander, an engineer with BJ Pipeline Inspection Service in Canada.
In the context of MFL technology, Sander talked about various pipeline features – corrosion, mechanical defects, structural pipeline components, along with the physical and magnetic parameters affecting the accuracy of identification, local and/or sizing of the defects. In the past, some of these features had not been detected, identified or reported, he stresses. Today, they constitute what he calls “a significant portion” of the training and testing procedure for certifying MFL data analysts.
“Inline inspection goes back to the mid- to late-1960s with a concentration initially on MFL technology for protection of internal and external corrosions,” according to Fraser Farmer, owner of Canadian-based PipeLink Associates, an Ontario, Canada-based pipeline integrity management company. In the 1980s MFL tools evolved into “high-resolution” inline detection tools and now are a very mature technology, Farmer said.
“In the mid-1990s, the ultrasonic tool came on the market, initially for metal loss, or corrosion, in other words. Then in the late 1990s crack detection ultrasonic tools were developed that work on both gas and liquid pipelines. Crack tools initially were centered on gas pipelines, using ultrasonics in a wheel configuration. Most of these tools have been retired now that more advanced e-mark tools are available.”
In terms of crack detection, Farmer thinks the technology has been “emerging very, very rapidly in the last few years and it is approaching maturity in a few cases, but there are still a lot of defects and anomalies that are not amenable to inline inspection.”
In the wake of the San Bruno transmission pipe failure last year in Northern California, Pacific Gas & Electric Co. (PG&E) has been under increased pressure from regulators and legislators to complete an inordinate amount of hydrostatic pressure testing of sections of its transmission system in high consequence areas (HCA). It is not high-tech, but the process is decidedly time consuming and costly.
Longer term, the San Francisco-based combination utility has its proposed new Pipeline 2020 program dedicated to advancing and modernizing the tools used in integrity management efforts in the North American pipeline system. That program is still awaiting state regulatory approval, but PG&E is not waiting, beginning some pilot programs in the interim.
Separately, the utility has plans to do 95 hydrostatic tests this year, covering 150 miles of its transmission pipe in HCA locations.
In the spring, PG&E performed hydrostatic pressure tests on sections of pipe in Mountain View in the Silicon Valley and Antioch in the upper East San Francisco Bay, carrying out both pressure tests and camera inspections, and it was planning to do the same in and around the area of the San Bruno rupture.
This work requires a lot of advance planning and notification of the local communities, calling for local work permits and coordination with local agencies. The utility must ensure that gas is rerouted and continues to flow to homes and businesses throughout the testing.
There are seismic defects that can fail the hydro tests; “the hydro tests will find the single weakest defect, the weakest link in the chain,” GE’s Foreman said. “But what it won’t do is tell you how many more serious, but not severe, defects are present.”
ILI will pick up the preponderance of cracks, while the hydrostatic test won’t. “That is what I mean when I say ILI provides more visibility,” Foreman said. And the pipeline has to be taken out of service for the hydro tests.
Longer term, PG&E’s 2020 Program, outlined to have industry-wide implications, plans to address overall pipeline safety from five areas:
1) With outside expertise, the utility is upgrading pipe segments with the goal of making all lines capable of state-of-the-art inspections, including the latest pigging technologies;
2) Expand the use of automatic or remotely operated shut-off valves on its 6,000-mile system;
3) Help development the next generation inspection technology;
4) Help set industry-leading best practices for integrity, safety and training programs; and
5) Enhance and expand public safety awareness programming at the local community level.
Drilling down on the next-generation technology, PG&E and other operators are envisioning smart pigging devices that are highly advanced and getting more sophisticated every day, but still have real limits.
Thus, these limitations warrant that hydrostatic testing be done, according to John Kiefner, a pipeline testing consultant, who noted that reducing operating pressures as PG&E has done in response to San Bruno can have “pretty much the same effect” as hydrostatic testing of the line.
“Reducing a pipeline’s operating pressure to 80% of what it was operating at is equivalent to a test to 1.25% of the operating pressure,” said Kiefner, Ph.D., PE, head of Kiefner and Associates.
Sunil Shori, the chief integrity management expert at the California Public Utilities Commission’s (CPUC) safety division, said the ILI tools are designed to cover areas that hydrostatic testing cannot.
The experts speaking at a CPUC symposium on hydrostatic testing in May agreed that regulations and focus have improved in the last 10-15 years in prioritizing integrity management of pipelines, and technology and greater industry best practice development have helped lead the way.
One way of finding problems and fixing them beyond hydrostatic testing is to use so-called external corrosion direct assessment, Kiefner said. “This is one way independent from hydrostatic testing to find areas of corrosion and fix them.”
Once a pipe is hydro-tested, is a direct assessment method good enough for testing for internal corrosion, or is an ILI method needed? The external direct assessment methods don’t apply to internal corrosion, Kiefner said.
“Hydro tests should not be used as a substitute for the direct assessments; you need both,” the CPUC’s Shori said. “Inline inspection is an ideal way to see both internal and external corrosion, but there is also a direct assessment method for internal corrosion. The hydro pressure tests for maximum allowable operating pressure in no way eliminate the need for other, future assessments.”
Richard Nemec is P&GJ’s West Coast Correspondent. He can be reached at: firstname.lastname@example.org.
“I believe that our R&D efforts are so widely distributed across out industry that they go unnoticed. In response, I recommend that the industry, research organizations and government create a pipeline safety technology road map that identifies and prioritizes our research needs.”
–Allan Bradley, Chairman, Interstate Natural Gas Association of America (INGAA)
“The hydro tests will find the single weakest defect, the weakest link in the chain. But what it won’t do is tell you how many more serious, but not severe, defects are present.”
–Geoff Foreman, Growth & Strategy Leader, PII Pipeline Solutions
In terms of crack detection, the technology has been “emerging very, very rapidly in the last few years and it is approaching maturity in a few cases, but there are still a lot of defects and anomalies that are not amenable to inline inspection.”
–Fraser Farmer, PipeLine Associates