A year and-a-half after a series of high-profile fatal accidents prompted the U.S. Department of Transportation (DOT) to announce a call to action to repair or replace aging pipelines, oil and natural gas trade associations say pipelines have never been safer. Industry representatives insist that fitness for service, not age, should be the major criteria in determining whether a pipeline is at risk.

DOT Secretary Ray LaHood in April 2011 launched a national pipeline safety initiative to repair and replace aging pipelines to prevent potentially catastrophic incidents. He called upon all pipeline operators to identify high-risk pipelines, then prioritize and accelerate critical repair and replacement work. He also called upon pipelines to know the age and condition of their systems. LaHood directed DOT's Pipeline and Hazardous Materials Safety Administration (PHMSA) to be given new powers and oversight.

LaHood, at that time, cited three separate gas pipeline incidents, each resulting in fatalities. They were:

  • September 9, 2010, an intrastate natural gas transmission line ruptured in San Bruno, California. The explosion and fire resulted in eight fatalities, multiple injuries and destroyed 38 homes. The investigation concluded that the pipeline failed because of an improperly welded section of pipe that had been installed in 1956 and was never subjected to hydrostatic pressure testing.
  • January 19, 2011, an explosion and fire occurred on a natural gas distribution system, killing one person and injuring five others in Philadelphia. The source of the gas leak was a 12-inch cast-iron gas main installed in the 1920s.
  • February 10, 2011, an explosion and fire in a natural gas distribution system killed five people and destroyed several homes in Allentown, Pennsylvania. The source of the gas leak was an 83-year-old, 12-inch cast-iron gas main.

Compounding the public relations problem for the pipeline industry was the Macondo offshore incident in April 2010. Although it involved a drilling platform explosion and fire, not pipeline integrity, it still resulted in increased public scrutiny of the entire oil and gas business.

LaHood said at the time that he was concerned with the reversal of a trend as pipeline-related fatalities were rising. After about a 50% decline in serious accidents from about 1990, annual fatalities had risen from nine in 2008, to 13 in 2009 and to 22 in 2010.

"Since Secretary LaHood's call to action, PHMSA and DOT have received numerous commitments from states to fast track the repair and replacement of the highest-risk (bare) steel and cast iron pipelines," Jeannine Layson, director of PHMSA, tells Midstream Business.

"Due to advancements in pipeline safety efforts, including increased inspection and enforcement, new technology developments and enhanced regulations, such as PHMSA's integrity management requirements, the service age is not the only indicator of a pipeline's safety," she says. "About half of the gas transmission and hazardous liquids pipelines were installed in the 1950s and the 1960s as the nation's interstate pipeline system was born. Pipelines built prior to 1940 account for about 4% of hazardous liquid and natural gas transmission mileage. Since the 1960s, the rate of construction of transmission pipelines has decreased per decade, while natural gas distribution pipeline construction, mileage and replacement have consistently increased over time."

Fit for service

The oil and gas pipeline industry generally agrees. It has learned that, while age of an asset is one of the variables of operational risk, the condition of the asset—its "fitness for service"—is the key, says Tom Miesner, president, Pipeline Knowledge & Development, a Houston-based educational training and consulting company. More important than age is what was installed, how it was installed, and how it was maintained.

"Buried steel pipe would corrode if not protected, so monitoring the operation of, and maintaining cathodic protection systems—coating, rectifiers and ground beds—is a key maintenance task. Properly protected from corrosion, the life of steel pipe is not infinite, but it is quite long, on the order of hundreds of years," Miesner says.

"Across industries, the development of technology over the past 40 or 50 years has changed the definition of maintenance from 'fix it when it breaks' to 'fix it before it breaks,' and the oil and gas pipeline industry is no exception," says Miesner, a former pipeline company executive who served as Association of Oil Pipe Lines chairman in 2001, when new safety regulations were passed.

"Internal inspection and other data collection devices, instrumentation and computer modeling have progressed to the point where maintenance personnel focus on understanding the condition of an asset and taking corrective actions to prevent failures," he explains. The industry understands that "failures can be extremely expensive" and that using preventive technology, with an emphasis on inspection, monitoring, prevention and detection, is much more cost-effective; plus, it is the right thing to do.

Miesner notes that pipelines made of cast iron, which have been identified as problematic, are limited to low-pressure natural gas distribution lines. No liquids or natural gas transmission line currently operating is composed of cast iron. The only remaining cast-iron pipelines in use for natural gas transportation are for gas distribution companies, and no local distribution company has laid cast-iron pipelines for a long time—"I would guess at least 60 years," Miesner says.

Regardless of whether the pipeline is old or new, if an integrity inspection identifies any type of problem—such as a corrosion issue, flawed weld or damage caused by digging—the pipe is repaired or replaced and prioritized for reassessment, says Terry Boss, vice president of safety for the Interstate Natural Gas Association of America, the trade association for gas pipeline companies. Advances in technology and maintenance practices have further improved the ability to prevent, detect and repair or replace a degraded piece of pipe.

Liquid pipeline operators in 2011 spent more than $1.1 billion on evaluation, inspection, maintenance and repairs of pipelines and storage tanks, collectively referred to as integrity management, says Andy Black, president and chief executive of the Association of Oil Pipe Lines. The split was $803 million on pipeline integrity management and $308 million on storage tank integrity management.

"The liquid pipeline industry safety record improved since the implementation of federal integrity management plans in 2002. The three-year average of pipeline incidents fell 59% from 2001 to 2011," Black says. "Pipelines are the safest way to transport fuel. Accidents are 3,000 times more likely to occur with a large truck, 38 times more likely to occur by barge and 25 times more likely to occur by rail."

Black adds: "Liquid pipeline operators are leaders in the use of smart technology to scan pipelines for imperfections in need of repair. New research is under way to develop the latest techniques to protect pipelines. Liquid pipeline operators perform in-pipe inspections, using high-tech tools called smart pigs, on 80% of their pipelines, much higher than other industries." Smart pigs are diagnostic robots that pipeline operators send through their pipelines to survey and collect data on any potential dents, cracks or other issues. Liquid pipeline operators are funding research to develop new techniques to overlay and integrate data collected at different times with different tools or techniques.

Like any long-lived asset, oil pipelines must be managed and maintained. "In the end, however, what the public, the regulators and the operators care about is performance: Did the oil stay in the pipe?" Black adds.

Missing records and rule changes

Record keeping, however, can be an issue. Before 1970, there was no federal pipeline safety oversight, INGAA's Boss explains. Pipeline design and construction followed engineering standards, but the companies did not have a requirement to keep records.

"The Department of Transportation's PHMSA recently released an advisory notice on the topic of record keeping. It is seeking to outline what records are necessary for a pipeline to show to allow that pipeline to operate at a certain pressure," Boss says. "The general idea would be that if the pipeline doesn't have the records, the regulator would ask them to test the pipeline.

"We still don't know if that would be a hydrostatic test or possibly an alternative technology such as in-line inspection, also known as pigging or smart pigging. These details—and the timeframe for inspection of pipelines that do not have adequate records—have yet to be laid out. We expect a final rule by PHMSA on this subject in a 2013-14 timeframe. In the meantime, pipeline companies are hard at work verifying records and other complementary documents," Boss adds.

Keeping thorough pipeline safety records is critical in a world where the public has heightened expectations, adds Chris Paul, counsel for McAffee & Taft, a Tulsa-based energy-focused law firm.

"San Bruno has changed everything for everybody," says Paul. "It called into question for regulators and the public whether the industry had enough, and accurate, information about their systems. The agencies now want proof of knowledge regarding the systems at levels of detail not previously required."

Paul continues, "The industry is finding in many cases that it did not keep adequate records, or records that it had never before been required to keep. So, now it is catch-up time, and some of the things (records) required may no longer exist, and may have never existed. Too frequently, if they did exist, they were not indexed or organized so they can be found. Those who found comfort in the fact that things had always been done a certain way are faced with a complete change of perception. A large part of the problem is that the government has changed the rules mid-game. They inspected for decades and did not find issues with records, and now suddenly have done an about-face.

"Power and authority can be misused and flexing of new muscle is counterproductive, if the easy course of punitive (action) is taken instead of a course directed towards progress. It is particularly disturbing when new rules and expectations are created unilaterally by 'guidance' or 'advisory bulletins' that circumvent legal procedures that would allow those with a better understanding of pipelines to provide necessary input," Paul says.

Regulators flexing their muscles

PHMSA, which closed a record number of enforcement cases in 2011, is intent on further strengthening its authority and oversight of federal pipeline safety regulations.

PHMSA, in a statement in August, said it plans to implement new rules enabling the agency to double maximum civil penalty for pipeline safety violations from $100,000 to $200,000 per violation per day. In addition, PHMSA will be able to collect a maximum of $2 million for a related series of violations, up from $1 million. Its most powerful enforcement tool is blocking the operation of a line and the agency's ability to impose corrective action orders, a list of demands, if it determines that a pipeline is "hazardous to life, property, or the environment." PHMSA is collecting more data about pipelines and stepping up efforts to educate the public about staying safe around pipelines.

PHMSA determines how and when to apply an order, based on the age of the pipe, the commodities being transported, the operating pressure, the surrounding area and any other factors it deems important. All new or replaced pipelines are required to have automatic shut-off valves.

The agency, in a February release, said it had resolved a record number of enforcement cases against pipeline operators during the last three years as part of its push to ensure full compliance with federal safety regulations. In 2011 alone, PHMSA issued 102 Final Orders, which are resolutions to pending enforcement cases and are issued once the agency verifies that all corrective actions are successfully completed and any fines have been paid. From 2008 to February 2012, PHMSA had issued 281 Final Orders to pipeline operators. The increased enforcement is a direct result of improved internal tracking procedures and rigorous investigations and inspections of pipeline facilities by PHMSA field personnel, says PHMSA Administrator Cynthia Quarterman.

The regulatory hand recently struck Enbridge Energy Partners LP following a July 27 pipeline rupture involving the release of about 1,200 barrels (bbl.) of crude oil from Line 14 of its 318,000 bbl.-per-day Lakehead System near Grand Marsh, Wisconsin. The August 7 restart was 11 days after the incident.

PHMSA demanded an exhaustive safety plan, which it and an independent auditor must review, for the entire 1,900-mile Lakehead pipeline system, not just Line 14. Enbridge was ordered to meet a series of safety provisions for the 467-mile pipeline segment where the rupture occurred that will apply to the entire Lakehead Pipeline System.

Provisions for the restart included restricting line pressure to 80% of the pressure used at the time of the failure. Greater pressure cannot be used until the cause of the failure is determined and adequate actions are taken. Enbridge also had to provide foot patrols of key areas, including pumping stations and values and aerial patrol of the pipeline right of way during and after the daylight restart to inspect for leaks. It was also ordered to give prior notification of the restart to emergency responders along the entire length of Line 14. A yet-to-be-determined fine is also expected.

Initial rhetoric directed at Enbridge was harsh. DOT's LaHood called the incident "absolutely unacceptable," and said that Enbridge would "need to demonstrate why they should be allowed to continue to operate this Wisconsin pipeline without either a significant overhaul or a complete replacement." Enbridge Line 14 corrective action was the 23rd for PHMSA since 2007.

Ironically, earlier in the same month that the Line 14 incident occurred, PHMSA had just issued a $3.7 million fine to Enbridge for a 2010 incident in which about 20,000 bbl. of oil leaked into Michigan's Kalamazoo River.

Enbridge, in an open letter posted on its website, said it will spend more than $800 million in 2012 to ensure the safety and integrity of its pipeline system. The letter, signed by Al Monaco, president of Enbridge Inc., said the company had invested about $400 million the previous year, and over the past two years had doubled the number of staff dedicated to leak detection and pipeline control systems and focused on tools, technologies and strategies to ensure the fitness of its pipelines. Enbridge, a Canada-based company, says it operates the largest and most complex liquids pipeline system in the world and during the last decade had transported almost 12 billion bbl. of crude oil, "with a safe delivery record of better than 99.999%," and is striving for further improvement.

Before 2010, the agency had rarely fined a company more than a $1 million. The $3.7 million penalty it issued against Enbridge for multiple violations associated with the 2010 spill was the largest to date. But, industry observers say that PHMSA is getting tougher and higher fines are likely.

For example, ExxonMobil, as of September, was still waiting for determination of the amount of a fine from a spill in its Silvertip line, in Yellowstone County, Montana, on July 1, 2011. That line was shut for 85 days. A rupture occurred after flooding scoured the river bottom and exposed the pipe. An estimated 42,000 gallons of oil leaked into Yellowstone River.

Regulatory workload

PHMSA's Quarterman said in a July presentation that the agency's workload from the past three years was greater than the seven-year period before that. She noted that the agency's funding is about $100 million annually and that President Barack Obama had sought an increase of about $67 million for fiscal year 2013, to nearly double the program's inspection and data staff. That increase has not received Congressional approval.

Those oversight duties have been expanded. Operators of liquids pipelines and natural gas transmission have for nearly a decade been subject to a growing amount of federal regulation requiring them to document and report pipeline safety data in a systemic and comprehensive way. But only recently were operators of natural gas distribution pipeline systems required to develop a similar plan. The new rules, referred to as the Distribution Integrity Management Program, were approved in February 2010, but gave operators until August 2011 to be in compliance, require distribution companies to write and implement a program to identify assess and evaluate the integrity of their pipelines.

Based on estimates from state regulatory commissions, Black & Veatch Corp., an international engineering/consulting industry, estimates that during the next five to seven years, costs may run in the $15 billion to $20 billion range at the utility level, for testing and replacement of at-risk pipeline infrastructure. "Given its (cast iron) inherent structural weaknesses, operators are moving forward with assessment and remediation programs to upgrade their systems with more resilient materials," says Bill McAleb, managing director of oil and gas, management consulting division, Black & Veatch.

The American Gas Association (AGA), the trade association for gas distribution companies, in a June report, wrote about gas rates and utility-cost recovery. That report said, in part: "Related to programs that provide for the replacement of cast iron and bare steel infrastructure are programs that recover the cost of maintaining and improving pipeline integrity." It continued, "Twenty-two states have implemented infrastructure cost-recovery mechanisms, and rate stabilization tariffs provided accelerated cost recovery in seven states." In 2011, natural gas utilities invested nearly $6 billion in their distribution system, according to the AGA report.

At the end of 2011, according to PHMSA, plastic and steel pipe made up 97.3% of the mileage of gas distribution pipelines. For incidents occurring on gas distribution mains, 35 were on cast/wrought iron mains, 11% of the 2011 total. "However, only 2.7% of the total miles of main are cast/wrought iron; indicating that the proportion of incidents is over four times higher than the proportion of cast/wrought iron main mileage. Incidents on cast/wrought iron mains are also more likely to result in fatalities or injuries; 37% of the cast/wrought iron main incidents included a fatality or injury; compared to only 21% of the incidents on other types of mains," PHMSA reports say. "The consequences of incidents involving cast/wrought iron gas distribution facilities are also striking when looking at the total number of fatalities and injuries. Over 12% of fatalities and over 9% of injuries were on incident reports where cast/wrought iron is listed as the material type."

High-risk infrastructure

PHMSA's Quarterman in December 2011 wrote to the National Association of Regulatory Utility Commissions, thanking it for promoting rate mechanisms to encourage pipeline operators to repair or replace high-risk pipeline infrastructure. That letter recommended state public utility commissions consider accelerating work on the following kinds of high-risk intrastate gas infrastructure:

  • Cast iron gas mains, which can be prone to failure as a result of graphitization or brittleness;
  • Plastic pipe manufactured in the 1960s to the early 1980s, which is susceptible to premature failures as a result of brittle-like cracking;
  • Mechanical couplings used for joining and pressure sealing pipe, which are prone to failure under certain conditions;
  • Bare steel pipe without adequate corrosion control (i.e. cathodic protection or coating);
  • Copper piping;
  • Older pipe, if it is vulnerable to failure from time-dependent forces, such as corrosion, stress corrosion cracking, settlement, or cyclic fatigue factor; and
  • Pipelines with inadequate construction records or assessments results to verify integrity.

Favorable rate structures enabling utilities to recover costs for infrastructure upgrade is likely to result in higher gas utility bills for customers. For example, the Florida Public Utility Commission in August agreed to allow three Florida natural gas companies to recover their costs for hastening pipeline replacement within 10 years.

Elsewhere, NiSource Inc. is undergoing a 1,000-mile pipeline modernization project of its gas transmission and distribution network of companies. The massive project will take place in Kentucky, Maryland, Ohio, Pennsylvania, Virginia and West Virginia. NiSource says it will invest more than $4 billion over 10 to 15 years to replace cast iron or bare steel pipelines. The DOT in April 2012 said it would lead efforts to expedite federal permitting for the project.

Also of concern for gas distribution companies and PHMSA are accidents caused by third parties. Annually about one-third of all pipeline incidents are caused by third-party excavations. AGA is cooperating with PHMSA's "Call Before You Dig" program, offering an 811 toll-free number to call for information about pipeline locations before beginning any excavation project.

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