Integrity Initiatives Address Growing Pipeline Safety Concerns
By Bradley Kramer
Operators, regulators and the public all have a stake in the matter, and pipeline integrity initiatives are on the rise. To meet governmental requirements and public expectations, pipeline companies have enlisted a variety of tools and services to take stock of their assets and measure the condition of their infrastructure.
Since the early 2000s, pipeline operators in the United States have been mandated to perform pipeline integrity maintenance on their pipeline systems on a recurring cycle, every five years for liquids and every seven years for natural gas lines. After a series of high-profile pipeline disasters — namely, the 2010 natural gas pipeline explosion in San Bruno, Calif., which killed eight people and damaged several houses — the U.S. Congress passed the Pipeline Safety and Regulatory Certainty Act of 2011, which requires pipeline operators to verify records of pipe located in Class 3, Class 4 and High Consequence Areas (HCAs) to ensure records accurately reflect the physical and operational characteristics of the pipe and confirm its maximum allowable operating pressure (MAOP). In short, operators must inspect their pipelines in high population areas.
Let’s break down those area classifications. A Class 3 area refers to an area with 46 or more buildings meant for human occupancy or a building (or “well-defined area”) occupied by 20 or more people on at least five days a week for 10 weeks in any 12-month period. A Class 4 area is any class location unit where buildings with four or more stories above ground are prevalent. HCAs are a bit more complicated.
Because the potential consequences of natural gas and hazardous liquids (e.g., crude oil) pipeline releases differ, so do the criteria of HCAs for those pipeline types. For liquids pipelines, HCAs are defined as populated areas (specifically urbanized areas), drinking water sources and unusually sensitive ecological resources (such as endangered species habitats or wetlands). For natural gas transmission pipelines, HCAs are determined by calculating an impact zone.
According to the Pipeline and Hazardous Materials Administration (PHMSA) website, an equation has been developed that estimates the distance from a potential explosion where death, injury or significant property damage could occur. This distance is called the “potential impact radius” (PIR) and is used to depict potential impact circles. Operators must calculate the PIR for all points along their pipelines and evaluate corresponding impact circles to identify the population therein.
HCAs are defined as those potential impact circles that contain 20 or more structures intended for human occupancy; buildings housing populations of limited mobility; buildings that would be difficult to evacuate; or buildings and outside areas occupied by more than 20 people on a specified minimum number of days each year.
These high population areas, as defined by PHMSA, foretell further regulation in the future, according to Richard Norsworthy, a NACE International corrosion specialist with Polyguard Products Inc.
“As our population grows, the need for more and safer energy also grows,” he explains. “We want to become energy independent, but with that there will be a need for many more pipelines, especially in more populated regions of the country. Therefore, more regulations will be enacted in an effort to protect these citizens, the environment and the surrounding communities. For the most part, these regulations will also protect the assets and future of the pipeline companies.”
While evaluating these assets may pose a financial challenge to pipeline companies, Norsworthy says, investing in pipeline integrity and maintenance will be a big payoff for the industry.
“This will be a growing cost, but if properly managed and funded, [it]will also pay great rewards to pipeline companies that are willing to properly implement and actually use the information provided to improve the integrity of their systems,” he says. “With international response to each failure event, these companies must protect their brand. Of course, the best scenario would be to never have a failure, but this is almost impossible because of all the variables that affect pipeline integrity. In the event of a failure, companies must have the information to back up their integrity efforts and be willing to share this information with regulators and other companies to improve the integrity of all pipelines.”
The leading culprits of pipeline failures are third-party damage, corrosion and mechanical failure. Regular pipeline integrity maintenance helps companies identify these problems and prevent them from becoming major disasters.
By collecting data on pipelines, Norsworthy says, qualified integrity personnel are able to properly interpret the information and provide an understanding of any issues with the pipe. Pipeline integrity programs often include pigging, inspection, testing, coatings and cathodic protection and new measures continue to be developed.
“With all the new tools and methods that are available to the industry,” Norsworthy says, “there has to be continuous training and growth within companies to achieve this process” of having skilled integrity professionals with the know-how to collect and analyze pipeline data.
Send in the Pigs
Pipeline pigging is often the frontline defense in the fight against pipe failure. Cleaning pigs keep lines free of debris, which is important for maintaining operational efficiency and preparing the line for further integrity maintenance. “Smart pigs,” otherwise known as inline inspection (ILI) tools, provide important data about the pipe itself, including proper shape and condition assessment.
Cleaning a pipeline is a crucial step before sending in the smart pig, according to Randy Roberts, N-SPEC applications and sales manager for Coastal Chemical Co. LLC, which is owned by the Brenntag Group.
“If you put a several million dollar tool in a line, a tool that is very sophisticated and designed to get high-quality data, obviously you want to get the best data you can,” Roberts says. “If a pipeline is filled with solids, it could lift off the tool’s instruments from the pipe wall. You want to maximize the ILI run. The cleaner the pipeline, the better the data.”
Roberts adds that there’s a bit of the “you break it, you buy it” caveat also involved in ensuring a pipeline is free and clear of debris before sending in that pricey inspection pig.
But a clean pipeline has side benefits too.
“In terms of pipeline integrity, pigging has a synergetic effect,” Roberts says. “Pigging with corrosion inhibitors along with a cleaner prolongs the life of a pipe. You also have other benefits, related to efficiency, with an increase in capacity and reduced horsepower. It maximizes throughput.”
Cleaning a pipeline regularly reduces maintenance costs, as it helps keep corrosive elements from collecting in the system.
N-SPEC combines mechanical pigs with a diluent cleaning solution to incrementally clear pipelines, a process Roberts calls “progressive pigging.”
“We take the solids off one layer at a time,” he says. “You could take all solids at one time, but then you’d have to deal with it at the end, and you don’t want to clog a pipeline.”
Regular pigging also keeps water out of pipelines.
“Water is an excellent diluent for cleaning, but it’s the worst thing you could have in your pipeline from a corrosion standpoint,” Roberts says, explaining that corrosion causing bacteria feeds on water when it otherwise may lie dormant in a pipeline. Water also rehydrates natural gas, which must maintain a dew-point standard according transportation regulation and could cause pipeline freeze-ups.
Testing Your Metal
Another important aspect of an integrity maintenance program is thorough testing, according to Jared Hebert, corrosion engineer at Coastal Chemical. By collection samples of the pipe wall, water and other elements removed during pigging, pipeline operators can get a better understanding of the condition of their system, whether there is wall loss in the pipe, if there is bacteria in the system and other crucial data.
Hebert stresses the importance of testing for the presence of organic acids.
“Through our collaboration with the University of Louisiana’s Corrosion Research Center, we’ve been able to mathematically link carbon dioxide pitting corrosion to the presence of organic acids in pipelines and well bores,” he says. “I believe that it’s negligence for companies not to look for these organic acids in water analyses when the corrosive impact of such species is known to exist.”
Hebert wants to raise awareness about the effect of organic acids in pipelines and suggests companies conduct a complete water analysis. By detecting these acids, companies can more accurately predict when corrosion is happening.
Other tests include coupon testing, which companies are supposed to conduct each year to analyze corrosion rates in a pipeline. Water tests can help determine what’s currently in a pipeline that could pose a threat to integrity. These tests can determine current corrosion rates and worst-case scenarios, and inform operators of the presence of microbial influenced corrosion (MIC).
Coatings are considered the “first line of defense” against corrosion, Norsworthy says. When coatings are properly selected and applied, coatings will provide many years of protection.
“Problems occur when the coating loses adhesion to the pipe, allow electrolyte between the pipe and the coating, which then allows corrosion to develop if the coating is cathodic protection (CP) shielding,” he says. “This is the No. 1 root cause of external corrosion for several companies in North America. These are not all older coatings. Some are seeing these problems with only a few years after application.”
Pipe coatings prevent electrolytes from coming into contact with the metal substrate, therefore stopping corrosion, Norsworthy says. The problem is that no coating is perfect and eventually all coatings will fail.
Determining how long a coating will last is a difficult question to answer without knowing the environmental conditions that will exist once the pipeline is buried, “Generically, the pipeline coatings that are used today will have a design life of approximately 50 years,” Norsworthy says, “but many will go beyond that.”
There are some methods of repairing these coatings, such as two-part epoxies that some companies use to recoat areas of damaged coating.
“As with all coatings, these have some problems, but they have a good reputation in the industry,” Norsworthy adds. “The mesh-backed tapes have become very popular because of their non-shielding to CP properties, easy of application and immediate back fill.”
Pipeline operators can also employ corrosion inhibitors to promote integrity, according to Hebert. Like traditional coatings, which provide external corrosion protection, inhibitors provide a barrier between the pipe wall and the internal elements. Corrosion inhibitors are injected into the pipeline as a liquid that attaches to the pipe wall to provide protection throughout its life cycle.
“There are two ways to apply an inhibitor, continuously or in batches,” Hebert says. “With batch treatment, the optimal time to apply the inhibitor is when the line is clean after maintenance pigging. You apply a film of corrosion inhibitor using a train of pigs, hoping to paint entire circumference of the pipe to provide protection until the next application.” Continuous treatment is conducted using a dedicated tank that is attached at the beginning of a lateral or trunk line to apply the corrosion inhibitor.
A pipeline integrity program can include all of these solutions. Pigging, ILI, testing and corrosion protection provide pipeline operators a measure of assurance that their pipelines are safe and running efficiently. These measures also keep operators in compliance with government regulations, and help ensure public safety.
“The No. 1 thing is if you don’t have a working pipeline, you can’t move or sell your product to market,” Hebert says. “But we’ve also seen recently the importance keeping a pipeline functioning and operating properly with the negative images of high-profile failures. If you have a good pipeline integrity program, it keeps your nose clean [with the government]and keeps good faith with public. And in our industry, that means a lot.”
Bradley Kramer is associate editor of North American Oil & Gas Pipelines. Contact him at firstname.lastname@example.org.