Gas pipeline suffers leak that could have been prevented through pipeline leak detection system and pipeline rupture detection

Pipeline Rupture Detection: A Path to Meet Minimum Rupture Detection Standards

In 2010, two pipeline incidents occurred, both of which had worsened impacts due to the time required to identify a rupture and isolate the incident. These two incidents led to the eventual introduction of the “Valve & Rupture Rule.”

  • Marshall, Michigan: An operator did not detect a rupture for more than 17 hours, leading to the unplanned release of 840,000 gallons of crude oil.
  • San Bruno, California: An operator was unable to isolate a gas transmission line for more than 90 minutes, leading to natural gas igniting and causing a fire.

In February 2020, PHMSA issued a notice of proposed rulemaking (NPRM), “Valve Installation and Minimum Rupture Detection Standards,” to revise the pipeline safety rules related to pipeline rupture detection for both natural gas and hazardous liquids.

According to PHMSA, the proposed revisions to the safety regulations are designed to mitigate ruptures and reduce the consequences of large-volume, uncontrolled releases of natural gas and hazardous liquid pipeline ruptures.

In July 2020, the PHMSA committees GPAC and LPAC met to discuss the proposed revisions to the regulations. The result was consensus about some aspects of the proposed rules, but also concerns about the applicability of the rulemaking in certain situations. As a result, there will need to be further discussion about the fine points regarding rupture detection included in the proposed rulemaking.

However, there are key takeaways for pipeline operators as you consider taking the ideal path to meet the minimum rupture detection standards when operating onshore pipe that is subject to federal oversight.

What is the Definition of a Pipeline Rupture?

In the proposed rulemaking, PHMSA attempted to introduce a definition of a rupture. Their goal was to quantify a rupture to create clarity for pipeline operators.

The proposed definition of a rupture for natural gas operators was a 10-percent / 15-minute rule. If a pipeline operator sees an unexpected 10 percent change in flowrate or pressure in less than 15 minutes, then the issue should be addressed as a rupture and appropriate action should be taken to shutdown and isolate.

The rulemaking is noble in its attempt to minimize adverse outcomes in the event of a rupture by clearly defining a rupture. However, as discussed during both the GPAC and LPAC meetings, the metric is not feasible in the majority of gas pipeline systems and liquid pipeline systems.

For example, the LPAC committee noted that liquid systems experience rapid hydraulic transients as a part of normal operation. The committee specifically discussed a new, modern system that recently placed into service. After conducting their research, they reported that the system would have produced dozens of false positive events where the 10-percent / 15-minute rule would have been met, but where no rupture occurred. The argument was that being required to shut down service during each such “rupture” would cause more harm than good.

Clearly, more work will be required on this aspect of the rulemaking. However, there is an important takeaway for pipeline operators.

PHMSA will likely allow for some flexibility in how the definition of a rupture applies to each operation. Specifically, there will likely be a different definition for gas versus liquid. The key is for operators to document the criteria their operation uses to define a rupture and then validate that the operation is following those criteria in their systems and procedures. In other words, “this is how we define a rupture, and can we prove that we’re able to identify such an event.”

Identification of a suspected rupture event is one critical step in the process. The second issue this rule addresses is the ability of the operator to timely shutdown the pipeline and isolate the event.

Responding to a Rupture

Again, a key takeaway from the discussion was that the nature of the impacts and mitigation are different for gas versus liquid pipelines.

Natural gas will be dispersed in the air, but is a fire risk until it is dispersed. In the case of the San Bruno incident, much of the damage occured due to fire that destroyed homes and spread as the gas escaping from the rupture was on fire and flowing at high pressure until the operator shutoff and isolated the line.

Liquids will flow on the ground to a low area where they collect or are dispersed into a waterway. In the case of the Marshall incident, the released liquid entered a waterway and the impact area expanded until the operator identified the presence of a rupture.

The proposed rule establishes a response time starting with the identification of a rupture, and ending with isolation. While the issues for gas and liquids are different and while the final rule will consider additional input, operators can likely expect no more than 30 minutes to isolate following identification.

Consider the System for Detecting a Leak versus a Rupture

The focus of leak detection is the detection of the smallest leak possible. By comparison, the focus of rupture detection is to address a rupture as quickly as possible. Further, the methods for effectively detecting a leak vary greatly for gas versus liquid systems. Historically, a Computerized Pipeline Model (CPM) is not an effective means to detect a small leak in a gas pipeline system.

If you’re looking to place a monetary value on potential impacts of a leak compared to a rupture, think about ineffective leak detection costing millions of dollars and ineffective rupture detection costing hundreds of millions of dollars.

That’s why optimizing a system for leak detection is different from optimizing a system for rupture detection. Both types of detection are required for a reliable Leak Detection System (LDS). An LDS can help pipeline controllers and support personnel in the following ways:

  • Quickly detect ruptures.
  • Reliably detect small leaks.
  • Accurately locate the presence of a leak or rupture.
  • Understand what a leak alarm indicates.
  • Execute the appropriate response.
  • Execute a timely response.

In the 2010 Marshall Incident, one of the factors contributing to the severity of the incident was that the operator misinterpreted alarms. As a result, the operator twice tried to restart the system before learning that a rupture had occurred. The consequence of the two attempted restarts was a significant increase in the volume of crude oil that was released from the system and leaked into the environment.

This incident highlights the need to have an effective LDS to find the smallest leak as quickly as possible before it turns into a rupture. Fortunately, there are industry best practices found in API 1175 to help pipeline operators develop the appropriate system that aligns with PHMSA guidelines.

Consider Adopting API 1175 to Support Leak Detection

The next step for operators is to consider implementing best practices to support leak detection. API 1175 is accepted as the industry standard for managing a leak detection program in a hazardous liquid pipeline. This includes how to select the appropriate LDS, how to develop the optimal leak detection culture and strategy, and monitor leak detection program performance.

While API 1175 is currently not mandated by PHMSA to support leak detection, this recommended practice is often incorporated by reference in PHMSA rulemaking. For example, in the NPRM that was issued in February, PHMSA referenced API 1175 as one of the recommended practices their agency will use to continue addressing the effectiveness of Leak Detection Systems for “other non-rupture type leaks through its rulemaking on the safety of hazardous liquid pipelines.”

Another compelling reason to adopt API 1175 in your operation is to align with the industry-wide goal of supporting zero incidents through the implementation of Pipeline Safety Management Systems (Pipeline SMS).

API noted in their API 1175 whitepaper that operators need a mitigation strategy should a release occur, and the appropriate leak detection program is part of successful mitigation. API 1175 provides operators with valuable guidance on what needs to be included in the program, including how to create the appropriate safety culture that supports leak detection.

Ultimately, taking this step will help reduce the likelihood of a leak advancing to a rupture and help your operation continue to meet the minimum rupture detection standards.

Talk to EnerSys for Leak Detection Support

Pipeline leak detection and rupture detection is increasingly valuable for pipeline operators as the industry continues to strive for zero incidents.

Additionally, the proposed rulemaking from PHMSA has pushed rupture mitigation efforts to the forefront, especially as the GPAC and LPAC committees continue to work through the proposed revisions to pipeline safety rules for natural gas and hazardous liquid pipelines.

As you review and weigh the applicability to your operation, we recommend taking an important step of implementing a leak detection system in alignment with API 1175 or a rupture detection system.

We are capable of developing a leak detection program for pipeline operators, helping to select or develop a rupture detection system, and also helping midstream companies review where some form of leak detection is applicable by law.

– Contact us today to discuss how we can support your operation’s efforts to mitigate rupture detection. We can be reached by phone at 281-598-7100, by email at, or by contacting us through our website.

– For more insight on the Valve Installation and Minimum Rupture Detection Standards NPRM, I recommend that you listen to my Pipeliners Podcast episode with industry expert Keith Coyle of Babst Calland. We discuss in-depth the GPAC and LPAC committee meetings and the impact of the NPRM on pipeline operators.