An unfavorable series of pipeline incidents during the past decade has led to a growing amount of federal regulations that have forced operators to document and report pipeline safety data in a systemic and comprehensive way. These rules have been in place for nearly a decade for hazardous liquids pipelines and natural gas transmission lines, but only recently were operators of natural gas distribution pipeline systems required to develop a similar plan.
The new rules, which require operators to develop a Distribution Integrity Management Program (DIMP), took effect in February 2010 and gave operators of distribution lines until August 2011 to write and implement their program. The rules are extensive and spell out how pipeline operators were required to identify, assess and evaluate the integrity of their own pipelines and to manage the risks from them.
"It starts with pipeline assessments to find potential failure points, such as cracking or corrosion, and then taking action to repair those flaws," says Robin Magelky, director of integrity management services for New Century Software. In general, pipeline integrity management programs are a series of actions designed to prevent incidents which cause damage to people, property or the environment.
The Department of Transportation reports there are about 2,000,000 miles of local natural gas distribution pipelines in the U.S., which transport natural gas to 65,000,000 retail natural gas customers. The new rule also applies to lines which distribute propane to 16,000,000 customers in the U.S.
Local distribution lines are downstream from the long distance transmission lines, operating between 0.25 pounds per square inch (psi) and 60 psi. Their construction can be steel, polyethylene-plastic pipe and, occasionally, cast-iron or wrought-iron pipe. As a general rule, distribution lines tend to be concentrated in highly populated areas and are regulated by state agencies.
Despite their differences, incidents can happen in both types of lines, according to the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA). Incidents in distribution lines continue to occur. On average, from 2005 to 2009 annually, gas transmission pipelines experienced about 78 incidents with one fatality and six injuries per year. Gas distribution lines reported about 73 incidents with more than 10 fatalities and nearly 41 injuries per year.
Formalize processes
The new rules for integrity management programs for distribution lines are fundamentally different from the regulations for long-distance transmission lines. The distribution lines operate downstream of the city gate stations and are almost always at a lower pressure than transmission lines. In addition, they are almost always located in densely populated areas, which change their risk profile.
For most local distribution companies, the new regulations formalize processes which were already in place and do not require huge changes in operations. CenterPoint Energy Inc., for example, already had an extensive inspection program in place before the new rules for distribution lines took effect. CenterPoint's natural gas operations deliver natural gas to 3,200,000 homes and businesses in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas, including Houston and Minneapolis. It operates about 71,000 miles of distribution lines in those areas.
Tal Centers, vice president of systems integrity and engineering at CenterPoint Energy, says the rules for distribution lines stem from a formal, seven-point integrity management plan which requires operators to describe how they plan to maintain the integrity of the system. "The point of the rule is to mitigate risk as reasonably as possible and to hold companies accountable," he says.
For years, much of the industry, including CenterPoint, had various forms and processes in place, but often lacked a coordinated and strategic plan for managing pipeline integrity from top to bottom. "The rule drove the industry, and CenterPoint as well, to make this a more formal, documented process. It increased documentation and education within the company and with the general public about how we are managing our facilities," he says.
"For many companies like CenterPoint, we were already doing much of what the rules require as part of our normal maintenance procedures. However, not all of them were formalized in a process," he says. CenterPoint has long had an active maintenance and safety program, but the new rules required additional analysis and reporting of that data to PHMSA.
"We had data and we had processes in place and we had organization in place, but there was not a top-to-bottom understanding within the industry of how to manage the risk around those assets," he says.
The rules require operators of distribution lines to write a comprehensive, seven-point management plan to manage the risk around the assets.
"The new rule focused on the industry doing a better job of knowing their systems," he says. A better knowledge of the distribution system would minimize the risk of an incident. Operators needed to know how the distribution system is constructed, the materials used, the types of valves, the pressures allowed and the potential threats that may cause the system to have a failure, Centers says.
Seven requirements
The written plan was quite detailed and required operators to describe how the system was first tested after its construction was complete. "They had all of these specific things that they wanted operators to know because, in certain instances, there can be different factors that could affect their systems," he says.
In some cases, when one distribution company acquires another, they do not always know in great detail the location and details of the assets in place. "In some cases, the records may not have been as clear as they needed to be," he says.
Once the system, its materials, assets and location are described in detail, the new rule requires operators to identify potential threats to the system, Centers says. Transmission lines generally run through sparsely-populated areas through a single line, so the danger posed by third parties is much less. For distribution lines, which have an extensive network stretching through urban areas, damage from third parties is much more of a threat.
The potential risks for distribution companies can come from someone installing a flower garden or swimming pool in their backyard. A subcontractor at a construction site may be installing or moving a water line. A street crew may be repaving or a telephone crew may be doing maintenance on one of its lines. This risk from third parties is the number-one threat to operators in the distribution industry, Centers says.
"We have an aggressive education program around the importance of calling 811 before all digging and around the consequences of not calling, including costly fines for damaged lines and serious injury or death," he says.
The written plan also has to identify potential threats based on the construction materials used for the lines. Modern lines are built of high strength steel or polyethylene, but some older lines are built out of wrought or cast iron. Studies from PHMSA have shown that wrought and cast iron are now a small minority of lines, but have a disproportionately high failure rate. Cast iron is not as resilient as other materials are today.
"Cast iron was a great material to use 50, 60, 70 or 80 years ago. It was state of the art, but it's not so state of the art anymore. Cast iron has its own set of threats," he says.
Once the threats are identified, the integrity management process requires operators to assess and rank the relative risks of each scenario. Risk is roughly calculated as the probability of a failure and the consequences of that failure in a given area. Once all of the assets have been ranked by risk, the plan requires operators to look for ways to mitigate that risk.
"A risk profile for an asset in downtown Houston or downtown Minneapolis is going to look different than a risk profile for an asset for a rural master planned subdivision," he says.
The fourth requirement requires operators to implement measures to mitigate those risks. This part of the plan could be as simple as developing a better public awareness campaign. The development of an active 811 (call before you dig) program is part of this requirement, he says.
The fifth requirement of the program is to measure performance, monitor results and evaluate effectiveness. CenterPoint, for example, tracks the number of damaged lines per 1,000 locations and performs a root-cause determination for each damage. About one-third of the damages to underground lines in the U.S. occurr from failure to call 811 prior to excavation. But since the 811 "Call Before You Dig" campaign was created in 2004, there has been roughly a 40% reduction in excavation damages.
Sharing results
The overall intent of the regulation is to improve safety. Using a metric like the number of damages to a line for every thousand locales allows an operator to normalize activity and compare one system to another. Locales refers to the number of times that someone has called 811 before digging. The goal is to improve performance and minimize the number of incidents, with the ultimate goal of eliminating incidents.
"They wanted those performance measures to monitor results and evaluate the effectiveness of your programs," he says. "This allows us to determine whether we are being more effective or less effective."
The next requirement of the new rule was to do a periodic evaluation and honest self-assessment. This was the one area that required the most changes within CenterPoint, Centers says. The company already had an extensive safety and maintenance program, but the process and the results were not always shared universally within the business.
Previously, the results of each test may have been kept within a corrosion department while an engineering department did its own studies. The pressure, regulation and odorization department also had their own respective controls, but there was no systematic sharing of this data throughout the organization. The new rules now require collaboration among all departments.
The new process makes for a more holistic approach to pipeline integrity, he says. "Now we can sit down and ask ourselves, are there things that we need to do this year to make next year better?'"
The new process has resulted in a better understanding of the system from top to bottom and allows for continuous improvement. "Years ago, our board of directors may not have known what distribution integrity was, but they do now. So this is driven all the way up the line," he says.
The final part of the new integrity management rules requires pipeline operators to report results to PHMSA. "They want to see reports, so your plans have to be on file with them. And then they want to see these measures and evaluations so that they can see you are actually doing what you said you are going to do," he says.
The new rules have forced operators to think systematically about pipeline integrity and have alerted the public safety issues and the need to cooperate with local authorities before digging in urban areas, although it's not clear if they have resulted in fewer incidents. "The distribution integrity management program has raised awareness and focus in multiple areas. However it is too early to measure the impacts from the program," concludes Centers.
Aging infrastructure
Integrity management programs have taken on additional importance as the U.S. infrastructure ages. "Many pipelines are over 50 years old and people wonder how long they will last," Magelky says. A sound integrity management program is absolutely essential to ensuring that an aging infrastructure does not fail.
In addition, a good integrity management program can avoid the cost of a pipeline failure. "The costs of an ineffective integrity management can be staggering," Magelky says.
He cited the September 2010 explosion of a 30-inch gas distribution line owned by Pacific Gas & Electric Co. in San Bruno, California, as an example. Eight people died in that incident and 35 homes were destroyed in the initial explosion and the ensuing fire.
"Aside from the tragic loss of life for which no value can be placed, PG&E recently stated the costs of testing and shoring up its gas pipeline system following the explosion could top $1.7 billion through next year," he says. "Integrity management is something most pipeline operators take very seriously, and for very good reason."
The federal requirements for integrity management programs for distribution lines, hazardous liquid lines and long distance natural gas transmission lines have spawned a small industry of consultants to help operators test and evaluate an integrity management process. Many of these third-party service companies offer solutions to help store and report the data required by the formal integrity management plan.
New Century Software offers a customizable DIMP solution for operators at various stages in the planning and implementation process, utilizing spatial risk analysis software.
Geographic information systems (GIS) applications are also essential to an effective integrity management system for transmission and distribution systems. These applications allow operators to record the spatial nature of asset data and to track information about potential threats to a pipeline's integrity and the consequences of a failure.
"It allows operators to make decisions about the construction and operation of their pipelines," he says.
GIS applications can be useful throughout the life of a pipeline, from pre-construction planning, as-built data collection and thorough integrity management to extend the life of the pipeline. "In addition, the GIS data can be a useful system of record for the transfer of assets from one operator to another," he says.
The new regulations for integrity management programs often require operators to integrate data from multiple sources into its management process. It often requires data conversion of one data format to another, migration from one database to another and alignment, or tying the data to specific locations on the pipeline. "All of this information is then available to systematically evaluate a pipeline's fitness for service and manage the integrity of the pipeline," Magelky says.
Looking forward, Magelky says he expects federal regulators to increase their focus on local gathering lines, which take crude and natural gas production from the wellhead to the longer distance transmission lines. There is growing pressure on federal regulators to include these lines in a future round of rules for integrity management programs.
A recent spill from a gathering line in Alaska, the encroachment of residential neighborhoods into previously remote areas and the development of the Barnett shale in the Dallas-Fort Worth metropolitan area have put pressure on PHMSA to regulate these lines more actively.
"Regulations have been added to encompass certain gathering lines and it appears that this trend will continue," he says.