Battling Corrosion: How Technology Has Changed the Fight to Protect Pipelines

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Fighting corrosion has been a key part of pipeline integrity management for almost 50 years. While the threats are fairly well known, technology has changed how the industry assesses and addresses corrosion control.

Pipeline companies have more data about their assets than ever before. How they use that data has a major impact on managing corrosion and extending the life cycle of pipelines and other facilities.

Not only must operators keep up with the staggering amount of data they’re collecting through integrity management assessments, but they also must keep ahead of increasing governmental regulations that continually move the goal posts for operational excellence.

Better technology and increased industry standards are all about improving safety, according to Drew Hevle, corrosion control manager at Kinder Morgan.

“Certainly, the concerns about protecting people, the public and environment are ever increasing,” Hevle says. “Standards for safety and the environment continue to raise the bar. Regulations are more and more stringent and broader. New technology and capabilities that we didn’t have in the past have been applied to continue to improve the safety of pipelines.”

One of the key considerations for improving corrosion control processes is the concern over aging infrastructure, according to Dirk van Oostendorp, director of engineering services for Corrpro.

“There are some very old pipelines still in service that were built in the mid-1950s,” van Oostendorp says. “Typically, when you design and build a pipeline, you design it to last for 25 years. Many of our pipelines are well beyond their design life. If you tried to replace them all, the cost would be astronomical. And there are no guarantees you’re going to get the permits to install a pipeline in the same location. Everyone is very focused on what I call geriatric rehabilitation to keep these pipelines operational.”

Corrosion engineer

Corrosion engineers have access to vast amounts of data that helps them understand the condition of a pipeline. Pipeline operators must integrate that data to make informed decisions about their assets.

Understanding the Threats

Pipeline corrosion is caused by a number of different factors. The presence of water in a pipeline, soil conditions, proximity of power lines, certain microbes, external damage, impurities in the pipeline — all of these are major causes of corrosion.

The first line of defense is the pipeline coating, applied both externally and internally, to protect against the environment where the pipeline is installed and the material flowing through the pipe. If the coating becomes damaged, there are methods for rehabilitating it as needed.

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Cathodic protection (CP) systems guard against exterior pipeline corrosion by applying anodes, rectifiers and DC currents to redirect corrosion to an anode that can be replaced.

AC mitigation protects pipelines that are built in parallel to overhead power lines. There are a number of ways to protect pipelines against AC interference, including fault shielding, gradient control mats, grounding systems and gradient control wire.

Microbially influenced corrosion (MIC) can be assessed using non-destructive evaluation (NDE) and compared to existing corrosion data. Proper mitigation is determined on a case-by-case basis, once the characteristics of the microorganisms present in the pipeline are determined.

External damage, from most commonly third-party strikes or installation errors, can also lead to corrosion by causing damage to the coating. Stress corrosion cracking (SCC) is another area of concern, caused by a combination of environmental, stress and material factors.

Further methods of corrosion control are based on pipeline integrity management systems, such as inline inspection (ILI), ultrasonic testing (UT), radiographic testing (RT), hydrotesting and other means.

A Mature Market

Corrosion control is “a fairly mature market,” Hevle says, referring to the knowledge of threats and the understanding of longstanding regulations.

“The initial regulations relating to pipeline corrosion came out in 1971, and many of them have not been changed since then,” he says. “There’s not a lot new in that regard. What is new is the availability of data from integrity assessments we can use to prioritize efforts to identify threats, to understand them better and where we need to apply additional resources for corrosion monitoring and mitigation.”

Corrosion threats are also pretty much the same as they have been for 40 years, Hevle says, explaining that a relatively new threat like AC corrosion came to light in the 1980s.

“Those threats are fairly well understood now,” he says. “We’ve had consensus on industry standards on how to address those concerns and regulations put in place to address them.”

However, a major change is coming to the industry. Hevle says the pipeline industry is awaiting sweeping revisions to natural gas safety regulations later this year. Known as the “Gas Mega Rule,” the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) is finalizing a set of rules that could double the number of pages of regulations that impact natural gas infrastructure.

According to a report from corrosion protection provider Matcor Inc., PHMSA’s proposed rulemaking will be broken up into three parts. The first section will address the expansion of risk assessment and maximum allowable operating pressure (MAOP) requirements to include areas in non-High Consequence Areas (HCAs) and moderate consequence areas (MCAs). Another part of the rulemaking will focus on the expansion of integrity management program regulations, including corrosion control to gathering lines and other previously non-regulated lines. And finally, the rulemaking is expected to focus on reporting requirements, safety regulations and definitions to include expanding into related gas facilities associated with pipeline systems.

“The trend of increasing regulations just reflects society’s expectations of higher and higher levels of safety,” Hevle says. “In the same way that public expectations are increasing, we also have a better-informed public than ever before because of the information available on the internet and social media.”

For an operator, the governmental regulations should act as a baseline for the minimum required corrosion protection, adds John Strong, technical field specialist for Polyguard.

“If an operator discovers corrosion on a pipeline the government regulations give a timeline for when a remediation is due,” Strong says. “A prudent operator will take this corrosion discovery as an opportunity to learn why it occurred. While the government regulations do drive most of the corrosion work performed on pipelines, it is also in the operators’ best interest to have a proactive stance when it comes to corrosion protection.”

In addition to regulatory considerations, corrosion protection providers are being asked to improve efficiency, says Keith Nevils, product director for pipeline services at Corrpro.

“There’s an impetus to do things faster or do it for less money,” he says. “It’s driving in both directions. On the efficiency and quality side, data collection is a big one. Because operators have to report to PHMSA on a regular basis, can you imagine if you had a binder full of papers that you had to look at every time? That’s a terrible way to manage your data, but still a number of companies are doing it that way.”

Lots of Data

New technology has made it possible to collect vast amounts of data about pipeline conditions, but technology has also made it easier to ensure data is accurate, Nevils says. For instance, a voltage meter can be outfitted with Bluetooth to enable a tablet computer to automatically import and view measurements. Technology allows electronic data collection to be pushed into a repository to find at any time.

“We may get some pushback in the industry with a resistance to technology,” Nevils says. “But more and more, we’re finding people who embrace technology.”

Hevle agrees, explaining how Kinder Morgan uses technology to build a robust database on its pipeline systems.

“We use a GIS system now that incorporates data not only from pipeline construction material, but from monitoring corrosion mitigation, as well as gas quality information from other sources,” Hevle says. “We have soils information and satellite photos that we can overlay in our GIS to show transmission power lines that we use to identify where we may have AC corrosion threats.”

Hevle describes how his job has changed since he entered the pipeline industry because of technology, noting that it has become a lot more computer-focused over the years.

“When I first started, it was a question of how to find information to make educated decisions,” he says. “Now we have to find a way to manage all the data we have to make those decisions. We have the opposite problem. We have more data than a person can process. We’re looking at different ways to present the data graphically and automate processes using algorithms to process multiple different components.”

Data Collection Kit in Use

Automated Accuracy

Automating data collection not only improves the accuracy of the information, it also improves efficiency and allows operators to make decisions quicker, according to Alasdair Stoddart, director of pipeline integrity management at Corrpro.

“Information collected from an asset is moving from having a technician in the field and data being collected with pen and paper, and then having the information typed into a document, to instead using electronic data capture,” Stoddart says. “That’s becoming a more integral part of asset management. As that trend continues, what we find is that the accuracy of the data becomes hugely improved. We find that the efficiency of gathering information is improved, and the real-time nature of the data is improved to the point where the asset owner has access to the information much faster than in the past.”

By automating data collection and getting the information quicker, Stoddart explains that the pipeline industry is able to move to a risk-based decision-making model, rather than time-based decision making.

Moving from prescriptive corrosion surveys to risk-based inspection (RBI) and quantitative risk assessment (QRA) driven intervals is where the industry should be moving, according to Daniel Ersoy, executive director of R&D at GTI. This is also well-aligned with the principles of distribution integrity management plans (DIMP) as required by federal and state regulations.

Changes to Come

While the pipeline corrosion market is mature, there are coming changes that could impact the industry in the next few years in terms of how corrosion control providers work with operators and how new technology will be implemented.

Stoddart sees pipeline operators looking to service providers to be stronger partners in the fight against corrosion.

“We’re looking to become an integrity partner with our customers, being more of a full suite provider from pipeline commissioning to monitoring thereafter,” he says. “Asset owners are looking for integrity companies to provide more guidance. Let the experts do the role they were designed to do more effectively.”

Nevils believes that there is still a tremendous amount of technology that can be introduced to the corrosion control market.

“What we’re doing with data collection, we’re like Google in the early days,” he says. “We’re building the repository for data, and now we need to do something with it, so we can become more predictive. That way we can get in front of the problem, instead of being behind.”

As computing power increases, Nevils says that the pipeline industry will be able to better understand the massive amounts of data it has and will continue to collect about the condition of its assets.

Ersoy agrees, noting how the Internet of Things (IoT) could impact the industry.

“IoT and other communication technology and protocols have the potential to change how we collect, pre-process, communicate and post-process corrosion-related data to make engineering, risk and integrity management decisions,” Ersoy says. “This might make it possible, especially for surface accessible locations, to have sensors for temperature, humidity and moisture, cathodic protection and pipe-to-soil levels, pH, conductivity, resistivity, etc., that are all real-time and communicated to a central database to enable more accurate risk calculations.”

Ersoy also believes that coatings will continue to improve.

“Interest is growing in novel and nano-based coatings for internal corrosion and flow improvement, as well as external self-healing and active passivation and sacrificial protection systems,” he says. “These coatings hold promise to provide improved corrosion resistance and system performance, while simultaneously lowering maintenance and repair costs.”

As the war against pipeline corrosion wages on, technology has changed and will continue to improve safety and integrity throughout the industry.

Bradley Kramer is managing editor of North American Oil & Gas Pipelines. Contact him at bkramer@benjaminmedia.com.

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