Adopting a preventative approach to leak detection

Figure 1. Tools such as the gPIM, a Guided Ultrasonic Permanently Installed Monitoring collar, can help operators assess metal loss features.

Hazardous liquid and gas pipeline operators are tasked with the responsibility of complying with the federal and state regulatory requirements for leak detection and monitoring on their piping systems. Yet too often, the focus has been on an “after the fact” approach using advanced monitoring techniques that include pressure drops, mechanical threats and changes along the rights-of-way.

Yet, most leaks have been detected by observation and people who externally communicated this information at these occurrences. In addition, little has been done to communicate internal tribal knowledge and integrity related legacy data to the employees in the control room. It has not always been apparent how to use this data effectively within these organizations.

The goal here is to discuss how pipeline operators can employ a more pro-active approach by making use of integrity-related data, information and issues such as internal/external corrosion, root cause of past leaks, and encroachment activities. Once this information is integrated with typical operating conditions, operators can create pro-actively model a potential leak event so that they will be better positioned to deal with one in the event of an accidental spill or release.

Integrating data
The integration of data is recognized as an essential aspect for pipeline integrity management. It is understood by the regulatory community that this information is essential in preventing and mitigating issues related to the pipeline. However, not all corrosion indications are directly examined and subsequently prioritized in accordance to their severity as related to the integrity of the pipeline. Therefore, this information should be available to all stakeholders within a company so that events can be anticipated. Unfortunately, this is the exception rather than the rule.

Back in the 1950s, 60s and even the 70s this type of information was indirectly communicated, because the organizations were smaller and everyone talked to each other. Today, companies have acquired many different types of assets. Some are geographically separated and long distances from each other; with others, the SCADA and control groups are remote from the pipeline system. The result is that the important integrity-related information typically does not get transmitted to all stakeholders unless there is a major incident.

The lessons of history

Figure 2. Acoustic emission sensors can be used to monitor liquid-filled pipelines.

To date, this author has found very few articles or studies devoted to the topic of integrating integrity information with the operations and leak detection activities. Yet some companies were very aggressive in their prevention and monitoring activities, even without regulatory requirements. For example, years ago a large natural gas transmission company located in the Northeast used line patrol personnel on a daily basis to monitor nearly 100% of their transmission lines in high density populated areas.

As a result of these activities, the company was able to reduce multiple near-misses (which stemmed from construction and encroachment activities) on a monthly basis while communicating this information to the controllers. Because of these aggressive monitoring activities, no accidents and no loss of life occurred. There was good communication among everyone in this area, including the land owners. They talked to each other and gas control group was located in this area. Today this is often not the case.

Let’s look at another example. In this case, the wrong information was transmitted with a different gas transmission company. Its Line 1000 was experiencing SCC problems and had a few incidents with gas releases. Line 1000 was interconnected to a newer line 1001, which was of a similar size and was not thought to have any problems.

When a failure occurred, the controllers had a difficult time differentiating which line was experiencing the problem, due to the multiple interconnects with customers and crossovers. They shut down the line with the SCC problems. However, they shut in the wrong line. Line 1001 also experienced problems due to hard spots – but no one remembered this information, because it was some time back when the last failure occurred. It took some time before everyone realized the mistake. Fortunately, there was no loss of life or additional damage. But, due to the precious time lost before the information was discovered, this incident could have been catastrophic.

We could look at many other cases. For example, there have been times where an in-line inspection was conducted and a particular site excavated. But, after excavation, operations personnel decided it was too difficult to dig out the pipe due to rock and other backfill issues. The excavation project was placed on the back burner until larger equipment, additional budget monies, and engineering studies could be deployed and performed.

In the interim, this information was not communicated horizontally to the controllers who monitor the pressure and other leak detection equipment. By the way, this scenario has occurred on both hazardous liquid and gas lines. Unfortunately, the level of corporate attention each incident received depended on how much press coverage occurred at the time. In all of these incidents, mistakes could have been avoided.

Communicating vertically and horizontally
Integrity integration offers a unique perspective into the leak detection and monitoring process. Traditional monitoring presumes that small leaks occur in hazardous liquid lines due to internal corrosion, and that small external corrosion leaks occur in gas transmission lines. To some extent, this is true.

Unexpected time-independent threats may occur on the pipeline. Examples include fatigue cracking, construction activities, encroachments and third-party mechanical damage. Time-dependent threats are microbiological influenced corrosion (MIC), hard spots, stress corrosion cracking (SCC), etc. These are some of the threats that have caught even the most experienced controllers off guard. Because unexpected threats will occur – such as fatigue cracking or third-party mechanical damage – these examples will result in catastrophic failure.

The role of the present controller is extremely difficult under current data management protocols. How can he or she make the right decisions without all of the right information? Can they shut in the right area of concern with minimal effect on safety and assets? Can these areas of concern be properly identified and the reason for failure properly identified? Reaction time is of the essence during a catastrophic event. Can we avoid the mistake of operating a pipeline after the warning of a potential failure? Proper communication of the historical integrity condition of the pipeline can improve emergency response time, and potentially save lives and property.

Who has this vital integrity information, and why is it not being communicated and integrated within the various departments? The Pipeline Hazardous Materials Safety Administration (PHMSA) has always said that an operator’s integrity program should work from the bottom up and top down, with information moving vertically both ways. But what is missing in this equation?

Information needs to be communicated horizontally as well, between players in the organization outside the narrow vertical column. This comment is made without placing blame. But it is to recognize that we tend to work remotely today; and because of the size of the organizations, we cannot even track who is in our department. Organizations have lost the “neighborhood effect.” It has been substituted with webinars and other remote communication. We get training according to the tasks that we perform. However, if it falls outside our assigned tasks, it is not considered our job.

Digging activities are another area where information needs to be shared. How much digging is going on, and where is it located?

One-calls are now automated and summaries of activities can be obtained that indicate the number of calls and responses. These summaries also contain information on where new subdivisions are planned or where trenching/construction activities are planned.

Basic steps for integrating information
As discussed above, the effectiveness of integrity information on all pipeline systems is essential. Here are some basic steps for integrating the necessary information.

• The first step is to open the lines of communication as it was done in the past using the neighborhood concept. With all of inter- and intra-net capabilities, this should be an easy task for most companies.
• Secondly, controllers do not need to know where every indication is on the pipeline; however, they do need the essential information. Meetings need to take place to determine what is essential information and data that could impact the integrity of the pipeline now and in the future.
• Third, training of both the controllers and integrity engineers needs to be accomplished where everyone know their roles and responsibilities.
• Fourth, prevention monitoring is part of the process. For example, there are permanently installed monitors that could assess the metal loss of several hundred feet at a time. Figure 1 depicts such a device. These devices can be placed at:
• Hazardous liquid pipelines at critical low points for internal corrosion
• Gas pipelines at cased crossings for external corrosion.

Another effective monitoring device is an underground or underwater acoustic emission (AE) sensor. These devices have been engineered for mounting directly on submerged structures such as offshore platforms and ships; or they can be used inside liquid-filled pipelines, vessels, chemical tanks or any other liquid-filled or surrounded structure. Materials “talk” when they are in trouble: with acoustic emission equipment, one can “listen” to the sounds of cracks growing, fibers breaking, and many other modes of active damage in the stressed material. These underground sensors are 100% insulated and non-conductive with an integral waterproof coaxial cable. They can be installed in depths of 1,000 ft (300 m). Figure 2 shows an AE monitor.

• The final step is to create new modeling that includes integrity related information and data.

Integrity engineers can predict corrosion rates which can be utilized in several places within the monitoring and prevention process. This data comes from a variety of sources, including in-line inspection; external or internal direct assessment (ECDA/ICDA); guided wave testing (GWT); hydro-testing, etc. The results or summary of this information can be integrated into the controller’s leak detection equipment and modeling systems to predict areas of concern. Where dynamic conditions exist – as with internal corrosion on hazardous liquid lines – PIMS and AE devices can be used to enhance the capability of understanding, so that leaks and spills can be prevented.

Conclusions
The goal here has been to propose a methodology than can help operators improve their leak detection capabilities through the integration of integrity data, improved communication, and enhanced training. The hope is that by refining their leak detection capabilities, operators can reduce the number of incidents in a controlled manner. The most important benefit of this approach is that operators can use it to proactively monitor integrity issues and prevent problems before they occur.

Regardless of how many bells and whistles are installed on a pipeline system, it takes communication with the public and within an organization to manage problems effectively before they turn into a detectable leak. As a result of integrating integrity-related information into the leak and monitoring process, this can turn an after-the-fact process into a true proactive prevention system, making pipeline operating conditions safer, as called for in the federal safety standards.