Category Archives: Pipeline Integrity

PHMSA Rule Making Updates – a look at what is ahead on the US Regulatory Front

The US Pipeline regulatory environment is poised to see several new rules implemented to expand the scope and effectiveness of pipeline regulations with a goal to improve the integrity and safety of hazardous material pipeline. These rule changes were all initiated years ago and have been winding their way through the regulatory process, soliciting input from the industry and from concerned citizens, environmental groups and other interested parties.

The Liquids “Final Rule”
In January of 2017 in the last few days of the Obama Administration, the Department of Transportation’s Pipeline and Hazardous Materials Safety Administration issued a final rule amending its Rule 49 CFR 195 that among other things expanded integrity management and leak detections beyond high consequence areas (HCA’s). The Final Rule tightened standards and broadened data collection and monitoring requirements for pipeline operators. A few days into the Trump administration, the White House issued a directive to federal agencies to freeze sending new regulations to the Office of the Federal Register (OFR) and withdrawing any regulations sent to the OFR. Thus the liquids “Final Rule” that was 6 years in the making was withdrawn and is awaiting resubmittal by the new administration.
While the exact requirements of the Final Rule may be changed, some of the key changes from the withdrawn rule included:

• Assessment of non-HCA pipeline segments every 10 years in compliance with provisions of 49 CFR Part 195.
• Increased use of inline inspection tools for all hazardous pipelines in HCA.
• Requirement for leak detection systems for covered pipelines in both HCA and non-HCAs.

PHMSA anticipates coming out with their revised “Final Rule” in the Fall of 2018.

The Gas “Mega Rule”
On the gas side of the pipeline regulatory environment, 49 CFR Parts 191 and 192, several public meetings have been held regarding PHMSA’s proposed gas rules, often referred to as the Gas Mega Rule. The rulemaking changes originally recommended would have nearly doubled the current number of pages in the regulations. PHMSA has announced that instead of one Mega Rule, the effort would be broken into three separate rules that are expected to be introduced in 2018 and to go into effect in 2019. Part 1 addresses the expansion of risk assessment and MAOP requirements to include areas in non-High Consequence Areas (HCAs) and moderate consequence areas (MCAs.) Part 2 of the rule making focuses on the expansions of integrity management program regulations including corrosion control to gathering lines and other previously non-regulated lines. Part 3 of the gas rule making is expected to focus on reporting requirements, safety regulations and definitions to include expanding into related gas facilities associated with pipeline systems.

Remediation Options for Aging Pipeline Coating Systems

A linear anode system may be an economical alternative to applying a new pipeline coating system or replacing aging pipelines.

by Ted Huck

Introduction: Addressing Aging Pipelines and Pipeline Coatings

aging pipeline coatingExternal corrosion is one of the significant threats facing pipeline operators worldwide. Historically, pipeline owners have employed a two-tiered approach towards mitigating corrosion risks. The primary defense against corrosion has been to apply a pipeline coating system that acts as a barrier, protecting the steel pipe from its environment. Cathodic protection is employed to supplement the coating system by providing protective current to the holidays or defects within the coating system. As with any aging structure, however, time takes its toll – for older pipelines this often results in an older coating system that starts to degrade in its primary function of protecting the pipeline from its environment.

This paper addresses the fundamental issue that many operators will face when evaluating their aging pipelines and pipeline coating systems. That issue is, quite simply, what is the best strategy to remediate an aging pipeline with deteriorating coating systems to maintain compliance with international standards for pipeline integrity. The options are to improve/upgrade the cathodic protection system, recoat the pipeline, or replace the pipeline. Each of these options will be discussed in detail and a decision matrix will be provided to facilitate the operator’s decision-making process.

Pipeline Coating Systems

Coating systems have been used on buried pipelines during the last hundred years and the technology continues to be the subject of significant research and innovation. Pipeline coating manufacturers are continually searching for better coatings to meet the varied needs of industry. Initially, the coatings were simple mixtures of crude pitches and solvents. These early bitumastic/asphaltic systems evolved into engineered coal tar enamel coating systems, which were prevalent into the 1960’s. The introduction of fusion-bonded epoxies (FBE) in the 1970’s quickly captured much of the pipeline market, although polyethylene, polypropylene and coal tar enamels are still used as well. The coatings industry continues to research and develop improved methods of providing more reliable and more economical coating systems.

When evaluating aging pipelines, coating condition is one of the critical issues that must be addressed. The coating provides the primary defense against corrosion and as the coating system ages and deteriorates, then the risks of corrosion increase exponentially. One of the challenges that must be addressed by pipeline owners is properly identifying the type and vintage of the coatings along a given pipeline. In many cases, different sections of pipeline may have different coating systems depending on the age of the pipeline and the standards in place at the time a section of pipe was installed.

Another critical consideration when evaluating aging pipeline coating systems is to identify whether the coating system fails shielding or non-shielding. Coating systems that fail in a non-shielding mode do not inhibit the flow of current making cathodic protection a viable alternative when considering how to remediate these lines. Other coating systems, principally tape coating systems, can fail in a manner that shields cathodic protection current and thus greatly reducing the possible remediation methods available.

Modern, over-the-line survey technologies have proven to be quite effective in evaluating coating quality and finding coating holidays. Technologies such as pipeline current mapping (PCM) which utilize a carrier signal transmitted along the pipeline with a receiver measuring the line attenuation along the pipeline length can accurately pinpoint areas of significant coating degradation even under concrete or asphalt. The information gathered using PCM in conjunction with pipe to soil close interval surveys (CIS) and direct current voltage gradient (DCVG) testing form the basis for identifying critical risk areas along aging pipelines. In-line inspection technologies using smart pigs also provide valuable data regarding coating quality.

Cathodic Protection

Pipeline coating systems are typically augmented by the application of cathodic protection. With a well-coated pipeline, cathodic protection can be economically applied to protect the coating holidays and defects by placing discreet anode beds that distribute current over long distances. In many cases ground beds can be located several kilometers apart and still provide sufficient current distribution to protect the entire pipeline. With some of today’s high technology factory applied coatings, the coating efficiencies are exceptionally high and the groundbed output requirements are very low. These discreet ground bed systems can either be deep anode ground beds or shallow ground beds located some distance off the pipeline.

Several issues must be considered when designing a cathodic protection system. These include coating quality, soil resistivity, available locations for electrical power, ground bed right of way issues, accessibility for maintenance, AC and DC stray current interference, and a host of additional issues. What is critical for aging pipelines is the regular evaluation of the effectiveness of the CP system. Frequently, as pipelines age and the coating quality begins to deteriorate, the CP systems are unable to provide sufficient current properly distributed to meet established cathodic protection criteria. In many cases, simply ramping up the output of the existing system or adding additional ground beds does not prove sufficient to address the problem.

Learn about soil resistivity testing.

Aging Pipeline Systems

Problem Identification

Aging pipeline systems with deteriorating coating systems suffer from poor current distribution and are characterized by areas of low potentials and exceedingly high levels of applied current density. The challenge with these pipeline systems is controlling current distribution to achieve the prescribed polarization levels consistent with international standards for adequate cathodic protection.

Figure 1 shows a deep well anode system with current output such that some areas are not meeting required off-potentials of -0.85 Volts to meet NACE criteria.

pipeline coating - insufficient cathodic protection

Initial Responses

The typical response to this problem is to increase the overall output of the deep well system (see Figure 2.) This generally does not alleviate the problems of not meeting the off-potential criteria and leads to over-polarizing the piping (potentials greater than -1.2 Volts.) This can result in coating disbondment further exacerbating the problem. The higher output current increases the ground bed’s consumption rate reducing operating life while raising operating costs appreciably. All this occurs without achieving the required levels of polarization to meet cathodic protection criteria.

pipeline coating - increased cathodic protection output

The next step that is taken to fix the cathodic protection current distribution problem is to add additional ground beds to reduce the distance between point sources. This too, proves to be an ineffective solution as the new ground bed provides only limited additional benefit (see Figure 3.)

pipeline coating - additional cathodic protection ground beds

Remediation Options

The problem cannot be economically resolved by the addition of an ever-increasing number of ground beds applying greater and greater amounts of additional current. The pipeline operator is then faced with a limited number of options: recoat the pipeline, replace the pipeline, or install a linear anode cathodic protection system.

Recoating/replacing is the only viable alternative for pipeline systems utilizing shielding type coatings such as tape wrap systems. Recoating costs typically run several hundred dollars per foot in open right of way areas and can be significantly more expensive in congested urban locations (these are ballpark numbers applicable to the United States and can vary significantly.) Recoating, when properly performed, can restore the pipeline coating system to an as new condition greatly extending the service life of the recoated section. The critical issue is to assure that the recoating is executed by an experienced coatings contractor with rigorous quality controls in place. Pipeline replacement is expensive and only performed when extensive third-party damage, significant corrosion or other extenuating circumstances warrant.

An economically attractive alternative to recoat/replace options is to utilize a linear anode configuration in lieu of point anode systems. This option is only viable when the coating system is non-shielding – this would include asphaltic and epoxy type coating systems. The application of a linear anode system typically costs between $20-30/foot in open right of way (again these are general price guidelines and can vary significantly.) In suburban or urban areas, horizontal directional drilling (HDD) can be an effective installation method with minimal surface disruptions. These linear anode systems eliminate the distribution problems experienced by point anode systems; they are in effect an infinite series of point anodes, which provide an optimum current distribution (see Figure 4.)

pipeline coating - linear anode system for optimum current distribution

In addition to confirming that the pipeline coating system is non-shielding and appropriate for the application of linear anodes, the linear anode system design must take into consideration the critical issue of voltage drop and its affect on current attenuation. Voltage drop can have a significant impact on DC power distribution to the linear anode system. Ideally, rectifiers would be located no further than half a mile to a mile apart, however, practical considerations including availability of AC power, right of way issues and other factors can force this to be extended further complicating the system design and affecting the installed cost.

While the design can be complicated by voltage drop considerations, one of the benefits of a linear anode system is that the power consumption is relatively low. Ground bed resistance, as determined by Dwight’s Equation, is significantly affected by anode length and this results in very low groundbed resistance values for linear anode systems relative to conventional ground beds. This makes the linear anode system much more suitable for low wattage power sources such as solar arrays and thermo-electric generators (TEG’s) than conventional ground beds whose wattage could be two or more times that of a linear anode system to achieve the same current discharge.


Aging pipeline systems with deteriorating coating systems present a difficult challenge to pipeline operators. The more the coating deteriorates, the more difficult it is to distribute current further away from the ground bed. The natural response to ramp up the ground bed output does an inadequate job of throwing current further but does result in increased current flow, higher current densities and over polarization near the ground bed further stressing the coating system. Adding additional ground beds also allows more current to be applied to the pipeline, but does not alleviate the current distribution issues. Ultimately, pipeline operators are faced with the choice of recoating/replacing the pipeline, or installing a linear anode system. The flowchart below (Figure 5) provides a decision matrix. Note that aging pipeline systems whose coating systems are determined to be in good condition through indirect and direct examination, require additional investigation to determine why criteria is not being achieved.

Aging pipeline coating decision matrix

For assistance with evaluating aging pipelines or installing linear anode cathodic protection systems, please CONTACT US.

Pipeline Rehabilitation and “Attenuation Deficit Disorder”

Around the world, the pipeline industry is seeing a growing number of “attenuation deficit disorder” outbreaks along their older pipelines. This is not a disease or a medical condition afflicting pipeline company personnel, but is a reference to a growing global problem with pipeline cathodic protection (CP) systems that are affected by older coatings that are failing. Pipeline operators need a solution for pipeline rehabilitation.

Pipeline Rehabilitation Solutions

Pipeline Rehabilitation ArticlePipeline operators worldwide are grappling with what to do as their 1950’s, once state of the art coatings systems start to fail. In our recent article in World Pipelines, Ted Huck examines two possible solutions for pipeline rehabilitation:

  • Recoating the Pipeline: At some point in the process of adding more CP stations and increasing the current output to levels that further degrades the coating, it becomes apparent to the pipeline operator that more drastic measures are required.
  • Rehabilitating the Cathodic Protection System: Under the right circumstances, an attractive alternative to the recoat approach is to consider the use of linear anodes as a rehabilitation strategy.

For additional information about these pipeline rehabilitation solutions, please read the full article in the September issue of World Pipelines. You can access the article HERE.

For assistance with cathodic protection design, MATCOR’s linear anodes for pipeline cathodic protection, project management or installation, please contact us at the link below.

Contact a Corrosion Expert

Not Just a Walk Along the ROW: Close Interval Potential Surveys

Close Interval Potential Surveys (CIPS) or close interval surveys (CIS) for those in the United States, are an invaluable assessment tool used to maintain pipeline integrity. Close Interval Surveys are frequently mandated by pipeline regulatory authorities.

Keys to a Successful CIPS Survey

  • Selecting a qualified survey crew
  • Advanced planning
  • Selecting the appropriate CIPS Type
  • Accurate CIPS Data Collection
  • Expert Data Analysis and Reporting

Close Interval Surveys (CIS, CIPS)Learn more about the keys to a successful CIPS survey and other considerations in our recent article appearing in World Pipelines, “Not Just a Walk Along the ROW” by Ted Huck.


Are you ready for spring close interval surveys?

MATCOR is here to help. Our experienced and NACE-trained crews are ready to perform close interval surveys to keep your pipeline cathodic protection systems in compliance and operating effectively.

  • Excellent safety record
  • Accurate, reliable data collection
  • Daily field progress reports
  • Extensive engineering and IT support

Contact MATCOR about your CIPS requirements or learn more about our close interval survey capabilities


Oil sands critics target a new concern – pipelines

The crude oil that is pulled from Canada’s oil sands is thick and heavy, a black tar-like substance that takes large amounts of energy and effort to make into end products like gasoline and diesel. Even some people in the Alberta energy industry describe it as “nasty” stuff.

But is it also dangerous?

Over the past few months, critics of the oil sands have taken a new tack. They are now arguing that oil sands crude, which contains more contaminants than traditional sources of crude, poses a risk to pipeline safety – and they’ve linked the recent spate of North American oil pipeline spills to what they say is the corrosive content of oil sands products.

It’s an argument that began with environmental groups, but has now been taken up by legislators. Last week, for example, Alcee Hastings, a U.S. Democratic congressman, warned that “the risk of an oil spill from these tar sands pipelines is very real.”

“The oil eats away the pipelines, compromising them and leading to frequent spills,” he said during a debate on the proposed TransCanada Corp. Keystone XL pipeline, which will bring oil sands crude to the U.S. Gulf Coast if it is approved. That echoes a February report from the Natural Resources Defense Council, an influential U.S. environmental group, which called oil sands crude a “highly corrosive, acidic, and potentially unstable” substance that “may be putting America’s public safety at risk.”

That conclusion has always been contradicted by industry, which has maintained that oil sands crude is safe. TransCanada, for example, has argued that it simply would not place at risk its $13-billion Keystone line by filling it with a dangerous substance. Yet the debate highlights the political obstacles that exist for the project, a crucial piece of infrastructure for getting the ever-rising volume of Alberta oil to market.

The two sides have left little middle ground between them. So who is right?

Interviews with academics, engineers and federal officials make clear that oil sands crude does indeed appear to pose additional risks. But those risks are largely borne by refineries that have had to deal with a dirtier and more corrosive substance than industry has been accustomed to.

In pipelines, independent sources suggest that the danger is substantially lower. Indeed, in decades past, thick bitumen was actually used to coat pipelines as protection against corrosion. And pipelines are partly shielded by the fact that they operate nearer room temperatures. Refineries, in contrast, process crude at up to 400 degrees Celsius, and the fierce heat promotes a series of chemical interactions that don’t happen at lower temperatures.

The corrosion question largely surrounds the properties of diluted bitumen, also called “dilbit.”

Oil sands producers generally produce two different products. One, “synthetic crude,” has passed through a sort of pre-refinery, called an upgrader, to transform it into a lighter substance that contains far fewer impurities. Dilbit comes from producers that don’t run upgraders. Instead, they take the oil sands crude and, with minimal processing, thin it with a lighter oil and pump it into a pipeline. As a result, it contains far higher levels of numerous noxious substances, including sulphur, acids, salts and sediments.

That in itself has raised some concerns.

Take sulphur, for example. Oil sands crude contains sulphur levels up to 10 times higher than other oil. But in dilbit, the sulphur is locked up with heavy oil molecules. As a result, it is largely harmless inside a pipeline, said Harvey Yarranton, a professor of chemical and petroleum engineering at the University of Calgary.

“You’d have to put it into reaction temperatures to release that sulphur – and those are above 300 Celsius,” he said.

Acids and salts are also found in substantially elevated levels in dilbit. But both substances are “not corrosive under pipeline conditions,” according to Natural Resources Canada, whose researchers have studied the corrosiveness of different oils. Acids need temperatures above 200 Celsius for corrosion to occur, the government said in a statement.

One area of concern remains sediments – little bits of sand that are embedded in oil. Industry measures these in pounds per 1,000 barrels. Conventional oil might measure 30 to 50 pounds per 1,000 barrels. Scott Bieber, a marketing manager with oil field services giant Baker Hughes Inc., has seen oil sands bitumen hit 500.

Sediments can contribute to corrosion in pipelines – and they have become a significant menace in refineries, where they have proven difficult to remove and help foul wastewater, Mr. Bieber said.

And environmental critics say that with the expansion in the oil sands, more study needs to be done of the effects dilbit has on pipelines. In particular, the thickness of oil sands crude – it’s far more viscous than conventional oil – creates friction inside pipelines that creates higher temperatures.

With Keystone XL, TransCanada has predicted temperatures as high as 55 Celsius. That remains far from the heat in a refinery, but higher temperatures do speed corrosion, and Anthony Swift, an energy analyst with the National Resources Defense Council, said governments both in Canada and the U.S. should take notice.

“There’s enough information out there about [the risks of] this stuff that merits a study,” he said. “The government should be protecting the public, and it’s a huge concern when they turn a blind eye to a potential danger.”