It’s a given: Most people take pipelines for granted. They’re there all the time, beneath pastures, below highways, running between subdivisions, around parks—quietly and reliably doing what they’re intended to do.

North America’s network of crude oil, gas liquid, natural gas and product pipelines extends a long ways. Kevin Garrity, senior vice president at the pipeline engineering firm Mears Group Inc. and past president of NACE International-The Corrosion Society, estimates there are 3 million miles of regulated pipelines in the U.S. The Canadian Energy Pipeline Association (CEPA) says its member firms operate a network of 110,000 kilometers (68,200 miles) of natural gas, crude oil and refined petroleum product transmission lines.

“Given the size of our infrastructure, we actually have an incredible safety record,” Garrity told attendees at the recent NACE conference. “Unfortunately, accidents by tanker-truck transport are considered more acceptable than accidents caused by pipelines that fail and rupture, and that’s a matter of expectations.

“The issue, of course, is that society realizes that every time you get behind the wheel of a vehicle, there is a risk associated with an accident. So they're more accepting of an accident by a tanker truck that might result in fatalities and injuries than they are when there’s an accident associated with a pipeline, and that is just the environment that we live in,” Garrity added.

Indeed, that network is admirably safe. The Association of Oil Pipe Lines (AOPL) says compared to pipelines, an accident is six times as likely to happen by rail, 13 times more likely by barge and 1,000 times more likely by truck.

AOPL statistics show crude oil pipeline spills declined 59% in the 10-year period ending in 2011 while spill volumes declined 43% in the same period. CEPA points to a 99.999% safety record for its members.

Maintaining—and improving—on that record takes a lot of effort by pipeline management. Most pipelines are out of sight and unexposed to weather or the public but that doesn’t mean there are no threats to their integrity.

Burying steel pipe in the ground, as surely as floating metal ships in seawater, by its nature creates the opportunity for corrosion. And as one speaker at the NACE conference put it, “corrosion never sleeps.”

Corrosion and pipeline material failures combine to rank as the leading causes of pipeline ruptures, according to AOPL statistics. The association says the pipeline industry spends more than $1 billion a year on integrity management—evaluations, inspections and maintenance. The industry is moving integrity management beyond heavily-populated, high-consequence areas and incident rates have been falling concurrently. The Interstate Natural Gas Association of America (INGAA) has been among the industry groups working to improve safety performance.

“INGAA members in 2010 committed to a pipeline safety plan called Integrity Management Continuous Improvement that is anchored with a goal of zero pipeline incidents,” Terry Boss, INGAA senior vice president of safety and the environment, tells Midstream Business. “Since that time, we’ve committed to an action plan setting out specific goals that include an expansion of integrity management beyond high-consequence areas, implementing management systems to promote a safety culture in the industry, reducing emergency response times and engaging our stakeholders.”

However, out of sight can be out of mind for the public. The industry sponsors extensive call-before-you-dig programs in every state—April was proclaimed “safe digging month” by the safety trade group Common Ground Alliance— and operators mark and monitor rights-of-way.

Corrosion conundrum

But ruptures still occur. Webster’s defines corrosion as “a state of deterioration in metals caused by oxidation or chemical action.” From its start in the 19th century, the pipeline industry has worked hard to find ways to head off the natural process that converts bare metal into various oxides over time.

Early-day “granny ragging,” in which construction crews slopped tar on pipes as they went in the ground, has evolved into exotic, high-tech fusion-bonded epoxy coatings, heat-shrinkable sleeves and other exotic coating systems that stand between the pipe and its environment.

In some cases, polyvinyl chloride or polyethylene pipe replaces the metal—but those materials have their own drawbacks. Cathodic protection also provides protection through an induced electrical field while hydrostatic testing stresses pipelines beyond normal operating limits while filled with water or other inert material.

But when things go wrong the results can be catastrophic for a pipeline operator. One of the largest incidents occurred in September 2010 when a 30-inch intrastate natural gas pipeline operated by Pacific Gas & Electric (PG&E) ruptured in San Bruno, California.

The National Transportation Safety Board (NTSB) report found the rupture released 47.6 million cubic feet of gas, which exploded. The rupture created a crater 72 feet long by 26 feet wide. “A pipe segment approximately 28 feet long was found about 100 feet away from the crater. The released natural gas was ignited sometime after the rupture; the resulting fire destroyed 38 homes and damaged 70. Eight people were killed, numerous individuals were injured and many more were evacuated from the area,” the NTSB reported.

That incident, with others, spurred the federal government to launch a pipeline-safety initiative to repair and replace pipelines as necessary, leading to legislation signed into law in 2011 giving the Pipeline and Hazardous Materials Safety Administration (PHMSA) stronger enforcement tools. The more-active Environmental Protection Agency is increasingly involved in pipeline and energy-industry regulation as well, although the agency has less expertise in the area, some industry observers say.

Improved records

Among other things, the 2011 act requires improved record keeping by pipelines—tracking what kind of pipe was installed, inspections since installation and any maintenance or repairs performed. The NTSB report concluded the San Bruno occurred at a point in the line that had been improperly welded when the line was laid in 1956 and never hydrostatically tested. It also requires pipelines to establish maximum allowable operating pressure (MAOP) limits for each segment of their systems.

For its part, PG&E announced recently that it has completed seven of 12 safety recommendations issued following the 2010 incident. Thus far, it has completed MAOP validations for “gas transmission pipelines running through high-consequence, populated areas” and was expected to have completed MAOP validations for its entire system last month. Also, it has developed contingency plans for planned work, a public awareness plan, improved record keeping “including retrieving, scanning, and uploading more than 3.5 million paper documents to meet the NTSB's threshold for traceable, verifiable and complete records,” comprehensive emergency procedures, 911 notification procedures when a suspected break occurs and revised toxicological testing “to ensure timely testing and inclusion of all potentially involved employees.”

Of the five remaining safety recommendations, the NTSB said it considers PG&E’s progress "open—acceptable pending completion."

“Our employees continue to work hard every day to make our natural gas system the safest in the nation," Nick Stavropoulos, executive vice president of gas operations, said in a statement. “We are making real progress that can be seen and felt by our customers, employees and regulators. We still have work to do to achieve our ambitious goal, but the change that is under way is real and measurable.”

Separately, PG&E announced adoption of new gas-leak detection equipment, the Picarro Surveyor, manufactured by Picarro Inc., which PG&E says is 1,000 times more sensitive than conventional methane-detection equipment.

Time and money

Any incident creates a lot of work that has siphoned off thousands of work hours and millions of dollars. That expense is in addition to any legal implications, which can be even larger.

In his NACE conference presentation, Garrity mentioned the 1996 rupture of an eight-inch line operated by Koch Pipeline Co. outside Lively, Texas. “Unfortunately, two children lost their lives. There was a jury trial associated with those fatalities, and the jury awarded $296 million in damages against the operating company. This is the aftermath of that particular failure involving a liquid butane line,” he said.

Those kinds of numbers are in addition to potential fines and even criminal penalties, added John Clayton, a partner with the law firm of Jackson Walker LLP, who has represented pipeline firms in multiple cases stemming from pipeline incidents.

“Some people laughed when I said fines will get up to $100 million,” Clayton told the NACE conference. “Don't laugh when I tell you that they will get up into the big one. And it's going to happen.”

When legal action starts after an incident, expect the Department of Justice to “subpoena the company’s records—and those records will go back clear to the construction of the pipeline, the historical records of the pressure, the incidents of leak losses, of the cathodic protection surveys—anything that had to do with corrosion and over-pressure operation,” he added.

“The regulators today and the justice department today don't fool around. They go after what they want right now; they don't give you time to hardly go look for it.

“If an incident occurs, blame-placing begins and assignment of criminal or civil responsibility begins, not only for upper management but for the middle management personnel and also for the engineers,” Clayton said. “If they, the regulators, didn't think that you could do something about it, you would not have been included in that litany of those that will be held criminally responsible.”

He added, “Upper and middle management and engineers are subpoenaed for regulatory commission, department and/or congressional hearings. Unfortunately, I've been to all these representing clients. You don't want to be there, and quite frankly, I don't want to be there.”

Political impact

Then there are broad political implications that can impact the entire industry—not just the single operator involved in an incident. A recent example of that potential impact was the rupture of ExxonMobil’s Pegasus line in Mayflower, Arkansas.

The operator was out the expense of evacuating 22 homes and emergency spill response, including 640 workers, 14 vacuum trucks and 60 storage tanks. The spill response recovered 12,000 barrels (bbl.) of crude oil and water. Yet to come are lawsuits and political fallout. The pipeline carried heavy Canadian crude to the Gulf Coast, and opponents of the proposed Keystone XL Pipeline were quick to make comparisons.

“An influx of tar sands on the U.S. pipeline network posed greater risk to pipeline integrity, challenges for leak-detection systems and significantly increased impacts to sensitive water resources,” the National Resources Defense Council said in a statement. Whether it will impact the pending decision to allow Keystone XL to be built remains to be seen—but it didn’t help.

“Safety is of paramount concern in the way we look at these applications and our national interest determination. It’s an essential consideration that we take into account, and we consult extensively, including with all of the expert agencies, so it’s one of the things that goes into our overall look at the Keystone [XL] pipeline,” Victoria Nuland, with the State Department said following the Pegasus incident. President Obama has said a final decision on the line will come from the department.

Separately, Chevron Pipe Line drew the ire of Utah Gov. Gary Herbert recently after the third leak of 500 bbl. or more of diesel fuel in three years from a Chevron line in the Beehive state. Herbert said PHMSA isn’t doing its job, and the state must step in. “This is just not acceptable. We need to take a more proactive stance,” the governor said at a press conference in Salt Lake City. The Utah Division of Water Quality also issued a violation notice for the latest spill, which occurred near the Bear River Migratory Bird Refuge north of Ogden, Utah. Federal regulators fined Chevron $500,000 for the two previous spills.

Both the ExxonMobil and Chevron lines are older systems, and there are industry concerns about welds performed on such lines laid before 1970.

Clayton told NACE attendees it’s important for pipeline management to invest the resources to assure ruptures don’t occur—that integrity-management program spot potential problems, operations follows up and there are records in place to document what was done and it when it was done.

“I'm asking us today to adopt a culture that you can drive that allows companies to have safety first,” he added. “Regulators and justice today demand safe operations. Public safety is the No. 1 priority.

Change the culture

“It’s hard for me to say to you that you're not demanding enough, but sometimes you aren't,” Clayton told the engineers and managers at the conference. “And now's the time to change that culture. Integrity management versus budget percentages is too one-sided. Percentage is too low for integrity, and the incident rate is too high … In today's world, somehow, someway, we as engineers and consultants for clients have to step up.”

Peter Elliott, a consulting corrosion engineer, made a similar observation in his plenary lecture at the NACE conference, pointing to the fact that the organization now has 30,200 members worldwide shows there is expertise available to improve integrity management.

“If you improve awareness, you improve reliability,” he said. “I believe in the past a lot of opportunities have been missed. The basic fundamentals are certainly known but somehow they get misinterpreted or misused or abused until they go out beyond, and become ‘unexpected consequences.’

“I do feel there’s optimism for the future, but we have quite a lot more to do, not necessarily in a complicated way, but certainly to address the awareness issue,” he added.

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