The industry responds to FERC's new safety regulations.
Utility companies are scrambling to understand and comply with the Pipeline Safety Improvement Act of 2002, which became law in December 2002. According to Daphne Magnuson, director of public relations at the American Gas Association (AGA), the act will require member companies to make significant changes during the next 10 years in how they operate.
The AGA is working with the Department of Transportation (DOT) and its Research and Special Programs Administration (RSPA), which operates the Office of Pipeline Safety. RSPA is writing the integrity management rule, due out by the end of this year, for natural gas transmission pipelines.
The act requires the Transportation secretary to issue regulations prescribing standards to direct an operator's risk analysis and the implementation of an integrity management program no later than 12 months after enactment of the law. The minimum requirement of the integrity management program requires a baseline assessment of all pipeline facilities. It requires that the assessments be completed no later than 10 years after enactment of the law, and that at least 50 percent of the facilities be assessed no later than 5 years after the date of enactment.
Magnuson characterized the act: "It's like Congress said, 'OK, go and inspect these pipelines every 10 years,' and RSPA takes it and says, 'By that we mean this percentage in such time and inspection techniques that we think are OK.'" She explained that DOT wants companies to add an extra layer of safety for pipelines that are in "high-consequence" or high-density areas. "When the proposed rule came out, AGA's largest area of concern was how these high-consequence areas are defined for different classes of pipes, and there is an added layer of complexity for how they determine impact range," Magnuson says.
AGA realized that its member companies could spend years trying to figure out which of their pipelines fall under which definition. "So we made a few recommendations to RSPA on how they can simplify that," Magnuson says. "Our biggest concern is getting this simplified, because depending on how you define this law, energy utilities that deliver natural gas are transmission pipelines-anywhere from 30 percent to 50 percent of our pipelines would fall under this definition of the law-which would mean they have to be inspected more frequently."
The ambiguity in interpreting the act is another problem, the association says. "We are given 10 years to complete the baseline, but I guess the way that some people have interpreted the law is that if you get your baseline assessment completed in five years, then you should just go forward and start reinspections again," Magnuson noted. "We're saying no … you're almost building in an incentive for waiting longer to complete the baseline. It's kind of the law of unintended consequences. If a company completes that baseline inspection early and then the deal is they have seven years to do the reinspection intervals, it just snowballs, and before you know it, as soon as you're finished inspecting you'll start inspecting again and again." AGA also asked RSPA to consider the amount of pressure the pipeline operates under, Magnuson says.
Companies that specialize in pipeline inspections are gearing up for the expected increase in demand as a result of the act. For example, Baker Hughes, a Houston-based gas- and oil-field services company, in late May acquired Cornerstone Pipeline Inspection Group, a privately held company that owns a fleet of "smart pigs" for making such inspections. It used to be that the so-called smart pigs, which are made of plastic and move through the pipelines, were useful only in cleaning the pipes, but now they are used to detect corrosion.
But Baker Hughes made the acquisition to improve its technology. Its existing pipeline management group was based on using tethered pigs. "This will be the first time we have added a 'smart,' or free-swimming, pig to our capability," says Kyle J. Leak, spokesman for Baker Hughes. "The Pipeline Safety Act will increase demand significantly, so whatever the supply was before, its relation to the demand has changed as a result of this new legislation," Leak says. "We're trying to put together as robust a platform as we can to meet that demand," he added.
But Magnuson points to a unique challenge for gas distribution utilities: Many local distribution company pipelines are not a straight shot, as are interstate pipelines; instead, they go around a lot more corners. "That means the internal inspection devices that Congress was so excited about-smart pigs and hydrostatic testing, [and] all the rest-really aren't very practical for numerous reasons on many of our pipelines," she says. "Not to mention they generally require you to shut down a portion of your pipeline to perform the test, which means no gas service. Some places … have parallel pipelines that can take over some of the load, but that is not necessarily true everywhere."
The Pipeline Safety Act also requires implementation of public awareness programs. But Magnuson says the AGA expected that, in light of the National Transportation Safety Board's (NTSB) recommendations that followed the El Paso Pipeline and the Bellingham incidents. She says the affected local communities expressed concern about being unaware of the pipelines' locations. So the AGA looked at a model the American Petroleum Institute (API) had developed years ago on pipeline communications and joined with the American Public Gas Association (APGA), Interstate Natural Gas Association of America (INGAA), and others in forming a task force to write voluntary industry guidelines and standards.
The audience for the guidelines includes elected officials and firefighters, in addition to the general public. Magnuson says the challenge was to come up with a template that would meet a big liquid gas pipeline's needs as well as those of a small municipal utility.
But the safety act presented a bigger challenge: meeting the act's Dec. 17, 2003, deadline for a formal public awareness program. "All of a sudden it went from being a voluntary industry consensus effort, to companies … [having to look] at a deadline and … comply with getting formal programs in place," Magnuson says.
The act's evaluation component is another challenge. "You can hire companies that will charge millions of dollars to conduct focus groups and do surveys and polling. It is expensive and time consuming," Magnuson says. "Right now that … looks to be our greatest challenge, to find a way to evaluate how effective our programs are and make sure we are not punished."
Improvements in safety technology may be the best answer to the public awareness issue.
The Gas Technology Institute (GTI), a nonprofit, Illinois-based research, development, and training organization serving energy markets, is working hard on improving technologies to prevent pipeline accidents.
A new technology to watch for is real-time monitoring of gas transmission pipelines. Because excavating equipment can cause great damage to pipelines, GTI is working to keep such disasters from happening.
Real-time monitoring involves using acoustic-based sensors that can detect third-party contact and notify natural gas pipeline operators in real time. GTI points out that when an excavating tool makes contact with the pipe, it creates acoustic waves that can move over large distances, as well as in the pipe wall and in the gas. So the company developed a system to attach a sensor to the pipe wall, finding they can be placed up to three miles apart under ideal conditions. But in the real world, GTI says it is more realistic to expect to have to place the sensor one mile apart in rural areas and a quarter mile apart in urban areas.
GTI has tested the sensor in the lab and is installing it at two urban sites in New Jersey. It aims to collect data on how urban noise affects the technology. GTI is working on the project with Battelle, an Ohio-based developer of products for government and industry.
A similar ongoing project involves right-of-way encroachment detection, whereby GTI hopes to provide a system to detect construction equipment entering a pipeline right-of-way before it can damage the pipeline. GTI is developing an optical fiber intrusion detection device to detect and sound the alarm when construction equipment is near a natural gas pipeline. But it also wants the system to be able to distinguish between a hazardous and benign encroachment.
GTI is working with the Department of Energy's National Energy Technology Laboratory to perfect a system whereby a long optical fiber is buried about 2 feet below ground and 2 feet above the pipe. Periodic light pulses would be sent down the optical fiber; in normal circumstances, little light is reflected back to the source. But when construction equipment is present, the ground above the fiber compresses and vibrates, changing the optical properties of the fiber and allowing some light to reflect back to the sources where it is detected. The location of the construction equipment is determined by measuring the time for the reflected light pulse to return. GTI believes the technology will make it possible to monitor a few miles of pipeline from a single location.
Jim Albrecht, GTI spokesman, says the system won't be field-tested for another year. But he expressed confidence that the technology has been proven in the lab.
Albrecht says keyhole technology could be a big issue because as much as 80 percent of a repair expense is due to excavation and restoration. If companies can bring the right kind of tools into a hole about 18 inches in diameter, they could save a lot of money, Albrecht says. "We're bringing it down to micro-excavation, where maybe you'll be able to enter and do repairs through openings as small as two inches," he says.
Albrecht noted that urban utilities, with much of their pipe networks buried under concrete and asphalt, are partnering with GTI on keyhole technologies. Washington Gas, Philadelphia's PECO Energy, Southern California Gas Co., New York City's KeySpan Energy, and Toronto's Enbridge Consumers Gas all are using new keyhole technologies in daily operations while working with GTI and others to advance the industry's ability to pinpoint problems and make repairs with greater precision.
Coastal Zone Interstate Pipelines: Are States Running the Show?
Donald F. Santa Jr., executive vice president at INGAA and former FERC commissioner, points to a recent problem pipelines are running into: States are using the Coastal Zone Management Act (CZMA) to delay or block the construction of interstate pipelines. Santa notes that CZMA works like a lot of federal environmental laws, such as the Clean Air Act, where functions are delegated to the states. If the states put in place a coastal zone management program that meets the federal criteria, they then can administer it. So when there is a federal action that affects the coast, the state needs to determine whether it is consistent with the coastal zone management plan. If the state determines that it is not consistent, then the applicant can appeal to the Department of Commerce, and its National Oceanic and Atmospheric Administration (NOAA) division handles those appeals.
"What has happened is the Millenium pipeline that NiSource and others are proposing and the Islander East pipeline that Duke and KeySpan are proposing have run into CZMA problems with the states of New York and Connecticut," Santa says. New York denied the consistency determination for Millenium and Connecticut denied the consistency determination for Islander East.
The interstate Islander East pipeline would supply natural gas to growing energy markets in Connecticut, Long Island, and New York City. It is equally owned by subsidiaries of Duke and KeySpan. And while all New York and FERC approvals have been granted, the project is stymied by Connecticut.
John Sheridan, spokesman for Duke and Islander East pipeline, explains the morass, saying the Connecticut House and Senate passed legislation to extend for another year the banning of cables and pipelines crossing Long Island sound. The legislation went to the governor's office on June 12, and he had until June 25 to either sign it or veto it. "On the regulatory side, regarding CZMA, back in October we had appealed Connecticut's denial of our CZM (application) to the U.S. Department of Commerce," Sheridan says. "Back in March, after having discussions with the state Department of Environment (DEP), we came up with additional engineering techniques out in the sound on the Connecticut side that would further reduce the impact to sedimentation. DEP somewhat agreed with our additional proposal, so we had asked the Commerce Department in June to remand the appeal back to the state in the hopes-and that is a big hope-of resolving the issue as it relates to sedimentation. The U.S. Department of Commerce has given the state DEP until July 31 to take action on our CZM application." Sheridan points out that because of this situation, "the spotlight has been on us for over two and one-half years now."
Santa sums it all up. "It really creates an interesting issue, because if you look at what the states are examining and what NOAA is examining in the appeals, in some ways it is a de novo review of that which FERC has already addressed as part of the certificate process. As we all know, FERC bends over backwards to solicit and accommodate the states as part of that certificate process."
Santa says INGAA's concern is that if these states succeed in what they are trying to do, it will set a precedent for any state where there is a CZMA program. "I think there are about 33 of them where, if a pipeline came anywhere near the coast, the state could put itself in a position where it could de facto override the FERC certificate," he says.
There is a provision in the proposed House energy bill dealing with the CZMA that INGAA favors and that would address issues pipes are starting to run into. Another provision that came out of the House commerce committee portion of the energy bill, while not directly changing the CZMA, states that the record developed by FERC in the certificate process will be the exclusive record for purposes of any appeals of other agency's actions.
"Under the current law, once the record is closed, the Department of Commerce has a limited period within which it has to make a decision on the appeal," Santa says. "The problem we have witnessed on the Millenium appeal is that NOAA forever seems to be compiling the record and never closes the compilation of the record, which means the clock never starts to run for when they need to make their decision." -L.A.B.
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