A training event put the focus on practical considerations of pipeline integrity in field conditions, offering detailed information on new construction issues, a regulator’s take on a spate of hydrotest failures, rehabilitation and replacement efforts on a 265-mile problem crude line, assessment of the sources of corrosion and remediation of cathodic protection over a 3,000-mile gas transmission system spread over three states.
“We’re showing you state of the art techniques on how to evaluate your pipeline,” President Mark Gluskin told an audience of 34 pipeline operators and regulators and 20 Mears employees at the Mears “Partnering in Education” training summit.
The event took place Sept. 19 at the company’s NACE-certified field test and training facility in Rosebush, MI. Speakers from Marathon Pipe Line, Piedmont, the Pipeline and Hazardous Materials Safety Administration (PHMSA) and Inline Devices joined Mears employees on the agenda.
Dan Wagner, vice president at Marathon Pipe Line Company, presented an in-depth look at a problem pipeline system. The Catlettsburg-Murphysboro crude oil pipeline in Kentucky was built in 1973 through 265 miles of rock with insufficient padding, according to Wagner, and although it experienced only one major emission, due to a crack with dent issue in 1980, the line has suffered consistent integrity problems.
“We’ve thrown everything but the kitchen sink at this line,” said Wagner, showing a tally of 4,500 integrity investigations between 1980-2012 and testifying to repeated failed coatings and repairs. “If [a repair technology] was available between 1973 and 2012, I’ve seen it on this line and I’ve seen it fail on this line.”
Using radiography, electromagnetic-acoustic transducer (EMAT) and dual-field magnetic flux leakage (MFL) inspection technologies, Marathon decided to replace sections of the pipe. The company asked for special cooperation with PHMSA to use the regulator’s knowledge on best practices, keeping its agents updated on the results of testing beyond regulatory requirements “to make sure that we got the best possible product back in the ground.”
“PHMSA’s our partner and our inspections are opportunities,” Wagner said, quoting Marathon’s CEO. “We want people asking ‘What do we need to do?’ and not ‘How much is it going to cost?’”
In the first phase of the project, completed last year, 27 miles of pipe were replaced. Seventy samples of the pipe removed were preserved for testing and work groups within industry organizations to investigate corrosion control methods.
Marathon revamped its decision-making process to handle accountability for the application of repair coatings in the future, and Wagner suggested that a change in expectations for repair coatings was due as well.
“We have [original] coatings in the ground across the industry that have been there 60 years and they look great. You go out there and dig them up and everything looks fine. So why is it that we don’t expect our repair coatings to last the same amount of time?”
Wagner encouraged other pipeline operators to reach out to technical groups and colleagues with problems on their own pipelines, emphasizing the industry’s willingness to cooperate when it comes to integrity management.
Ken Lee, director of engineering and research at PHMSA, shared information about a new PHMSA-funded project on quality management systems.
“We’ve seen a lot of new construction issues, including hydrotest failures of brand-new lines that are built to supposedly the highest standards in the industry. We’ve been alarmed and concerned by that so we’re going to find out where the gaps are, what the issues are, where these failure modes are and prevent them from occurring.”
Lee displayed a series of photographs, taken in the field on new construction projects within the last two years, where pipe has passed mill ultrasonic testing and met codes but showed clear defects or failed tests. Girth welds, high-frequency electric resistance welding (HF-ERW), low-strength bends and repair welds all merited special mention. He recommended ultrasonic or X-ray radiography on a 24-hour delay over gamma ray radiography to increase the probability of detecting cracks.
Lee also discussed plans to strengthen PHMSA’s integrity requirements for existing pipe, including the National Transportation Safety Board’s recommendation to remove the grandfather exception for pipelines constructed before pressure testing was required. He detailed a push to expand integrity management programs outside of high-consequence areas (HCAs). A proposed definition of a “moderate consequence area” (MCA) would include all locations with any population within a potential impact radius.
That definition would mean that HCAs and MCAs combined would contain 91,000 miles of gas transmission lines, nearly a third of the 300,000 miles of gas transmission pipe in the ground. Lines with no record of pressure testing or with a history of failure would be the highest priority for any new guidelines.
Don Mitchell, manager of integrity systems at Piedmont, presented with Mears senior vice president of operations, Alan Eastman, a comprehensive program for cathodic protection remediation applied across Piedmont’s nearly 3,000 miles of gas transmission pipeline in North Carolina, South Carolina and Tennessee. The system includes pipe dating back to the 1940s, and after completing HCA surveys and close internal surveys (CIS) in the early 2000s, Piedmont determined that it needed more comprehensive information about the cathodic protection on its pipe. The program was designed to take 10 years.
“We didn’t want to be a San Bruno,” Mitchell said. “We didn’t want to wait until an incident happened. We wanted to be proactive and do it up front.”
Intended to ensure integrity and prevent degradation, the program focuses on evaluating the whole system to provide baseline measurements, prioritize intervention on any developing problems and track changes easily. It also integrates data gathered through the program with historical inline inspection (ILI) and CIS data and any other reports that might be available to help determine the best course of action for a given stretch of pipe.
The massive scale of the undertaking and the proactive nature of the work have allowed Piedmont to choose methods of remediation strategically and consistently. “You don’t want to take an approach of recoating in a given year for the same situation where next year or the year before you added CP. You want to take what you’ve learned in your pipeline system and your geography and try to establish what works,” said Eastman.
Eastman lauded Piedmont for its forward thinking. “We all do CIS and we all fix the bad ones. They’re committed to fix it all. And they’re committed to do it in a defensible way, to use the data to select the most efficient method of remediation. At the end of the 10 years that whole system is going to benefit—it already does.”
Outdoors, the pipeline systems at the training facility hosted live demonstrations of several methods of inspection to reveal examples of integrity and corrosion problems.
Kevin Garrity, senior vice president of special projects for Mears, led a discussion and demonstration of forensic analysis of corrosion, providing “a road map of what happened and why it happened” that would allow operators to determine the severity of a corrosion problem and prevent it from recurring. Microbial involved corrosion (MIC), DC stray current corrosion, AC stray current corrosion, and active vs. final-state corrosion were all shown, along with the diagnosis and testing processes to identify them. Garrity also gave case studies of known pipeline failure incidents traced back to different types of corrosion.
Field personnel demonstrated new equipment for defect mapping via handheld laser, onsite data entry and instant dissemination via data cloud. A 12-inch ILI tool ran through the training facility pipeline to demonstrate instant reporting capabilities.
“We built this thing eight years ago, and I was very proud of it,” Gluskin said of the training facility, composed of five pipeline systems, four cathodic protection systems, and varied coating and hookup configurations, although Gluskin pointed out that with most of the components buried, “it looks like a big square piece of dirt.”
The opportunities the arrangement presents for training, testing and demonstrations are significant enough that it will soon be less unusual. Gluskin announced that Mears’ parent company, Quanta Services, has bought a 2,200-acre ranch near La Grange, TX, to develop into a larger training facility for pipeline and electric power applications.
“We’re going to replicate this [facility] 10 times over with a big emphasis on ILI testing and vetting out ILI tools, as well as incorporating everything we have here,” Gluskin said.