U.S. industrial history has had a regrettable record for gas accidents and gas pipeline explosions, to the extent that there are now well-documented lists of major and not-so-major incidents dating back over the last century. More than 200 gas explosions still happen annually, and that picture has not improved in the past decade. The following edited list shows the alarming frequency of gas / gas pipeline explosions over a 20-month period.
- June 2015: Four workers were injured when a pipeline exploded at a gas booster station in White Deer, Texas.
- August 2015: A Boardwalk Pipeline Partners / Gulf South Pipeline Company underwater pipeline off the coast of Louisiana ruptured and exploded. Two workers were injured.
- April 2016: Two workers died when they struck a pipeline at the Southcross gas processing plant in Bonnie View, Texas.
- April 2016: A 30-inch pipeline in Salem Township, Michigan—operated by Spectra—exploded. The incident severely injured a worker and caused the evacuation of local businesses and homes.
- February 2017: A natural gas pipeline operated by Phillips 66 in St. Charles Parish, LA, exploded, injuring three workers.
- February 2017: A natural gas pipeline operated by Kinder Morgan in Refugio, Texas, exploded, creating a massive fire. The explosion shook homes 60 miles away.
That’s a grim toll for the industry across a 20-month window, and that’s only an abridged list.
Fragments of pipeline among the gas line explosion damage in California, 2010. (Source: Bryan / Wikimedia Commons)
The Industry Must Begin to Correct Its Past
For decades, the U.S. oil and gas sector has lacked rigorous legislation on the safe transmission of gas. Throughout this period, operating errors, equipment failures, and natural causes have all accounted for pipeline failures and gas leaks. One unfortunate characteristic of the pipeline and related asset industries is that their early days and ownership lack in documentation, specifications, operating data, etc. This is often exacerbated by asset transfer through industry consolidation.
Any industrial accident or any human casualty is always one too many. However, it took a long catalog of gas disasters to precipitate better regulation on pipeline safety. Only in 2023 was the process completed and came into effect with the “PHMSA Mega Rule.” It addresses operational safety, monitoring, and data gathering in a way that thoroughly modernizes the documentation and performance safety of the gas pipeline industry.
What Is the PHMSA Mega Rule?
The Pipeline and Hazardous Materials Safety Administration (PHMSA) ruling was originally prompted as a direct result of the 2010 Pacific Gas and Electric Company rupture and release in San Bruno, California. It was the largest gas explosion in recent times, and its consequences included:
- Eight people killed
- 58 people injured
- 38 homes destroyed
- 70 homes damaged
Devastation in San Bruno, California, which was caused by the gas pipeline explosion. (Source: Brocken Inaglory / Wikimedia Commons)
Consequently, the incident started moves toward greater legislation for the U.S. gas piping sector. The set of regulations took years to put together and is so far-reaching that it’s organized into three parts. This comprehensiveness is why it’s called the “Mega Rule.”
Following pressure from the U.S. Government to legislate on greater safety in the gas piping sector, and following a huge breadth of consultation input, the PHMSA Mega Rule was established. This trinity of regulatory frameworks governs gas transmission pipeline safety after accidental releases through pipeline leakage or when pipeline failures have occurred. It mirrors a pre-existing set of rules for liquid transmission pipelines and amounts to a decade-long revision of gas pipeline safety legislation. The scope of the Mega Rule protects more than 300,000 miles of U.S. coastline where onshore gas transmission takes place. The three-part rule also has implications for inland pipeline safety.
PHMSA Mega Rule Part 1 Emphasizes Operational Safety and Maintenance
Part 1 increases the safety levels for onshore gas transmission piping and requires the retention of data relating to performance attributes (specifications) and inspection (data collection). It also requires that asset owners ascertain the maximum allowable operating pressures (MAOPs) for pipelines if they have been hitherto unknown, or to reconfirm what these operating parameters are. PHMSA has approved various techniques for doing this:
- Pressure test
- Pressure reduction
- Pipeline replacement
- Engineering critical assessment
- Pressure reduction (for pipeline segments where there is a potential impact radius less than or equal to 150 feet)
- Alternative technologies
Previously, it was permissible that the highest pressure recorded in a pipeline in the five years preceding 1970 would be satisfactory. However, Part 1 overrules that, with the exception of assets working at less than 30% of the specified minimum yield strength or pipelines operating in the Class 1 and Class 2 areas.
Class 1 and Class 2 areas are also known as high-consequence areas (HCAs). These are areas where there are more than 20 buildings in the impact radius. A secondary level of Class 3 and Class 4 areas—also known as medium-consequence areas (MCAs)—have been defined as areas with more than five buildings in an impact radius.
PHMSA Mega Rule Part 2 Emphasizes Monitoring and Mitigation
Part 2 of the ruling concerns the protection and repair of gas transmission pipelines. It has a special focus on the following:
- Repair criteria
- Improvements in integrity management
- Cathodic protection
- Risk assessment
- Management of change
Since coatings are the primary means of pipeline protection, this rule is specifically concerned with all aspects of coatings on pipelines. For example, correct application, correct selection, and monitoring coating integrity will ensure complete pipeline protection. This is especially critical in the first six months after construction.
The implications of Part 2 for the industry may be divided into those for internal corrosion and external corrosion.
Internal Corrosion
Where corrosive gases are transmitted onshore through pipelines, operators must implement a monitoring and mitigation program to identify any corrosive constituents in the gas and to mitigate any such corrosive effects. Monitoring by coupons or other measures is required twice per year and not more than seven and a half months apart.
In segments where potential corrosion contaminants occur, technology to mitigate any potential corrosive effects is required. Suitable technologies may include product sampling, corrosion inhibitor injections, in-line cleaning pigging, separators, or other means. Where these evaluations are necessary, they’ll be required once a year and not more than 15 months apart. In addition, mitigation and monitoring programs should be reviewed annually.
External Corrosion
To monitor external corrosion, annual voltage surveys as well as measurements of alternating and direct current are required to check for risks of corrosion or safety. Plans for addressing such risks must be formulated within six months of the survey. Furthermore, remedial measures needed to stop the risk are to be implemented within one year.
PHMSA Mega Rule Part 3 Emphasizes Data and Reporting for Rural Gas Gathering Lines
Part 3 of the ruling applies a set of minimum safety requirements to certain onshore gas gathering lines of large pipeline diameters that operate at high pressures and that are found in rural areas. The rule doesn’t affect offshore gas gathering pipelines, but implementation of the Part 3 requirements will:
- Prevent and detect threats to pipeline integrity.
- Improve public awareness of pipeline safety.
- Improve emergency responses to pipeline incidents.
Asset owners must report incidents and file annual reports to collect data on the condition of transmission pipelines previously exempt from federal reporting requirements.
Natural gas pipeline construction work in a remote forest area. (Source: Maksim Safaniuk / iStock)
Emergence of a New Pipeline Classification
Part 3 also provides for a new “Type C” regulated gathering in Class 1 locations that have outer diameters of 8.625 inches or greater and that operate at higher stress levels or pressures. The safety requirements for Type C lines vary according to the outer diameter of the pipeline and the potential consequences of failure:
- Type C gathering lines with an outside diameter greater than 16 inches and certain other Type C gathering lines that could directly affect homes and other structures have to comply with existing requirements for “Type B” gas gathering lines. There are also other requirements that operators develop and implement emergency plans.
- Type C gathering lines with smaller diameters—where failure could not directly affect homes and other structures—have fewer requirements. These are limited to damage prevention, emergency plans, and public awareness. The requirements address known causes of pipeline failures, including excavation damage, corrosion, and inadequate design and construction standards.
Implication for the Industry
The PHMSA Mega Rule Part 3 emphasizes the roles of asset owners and engineers in monitoring and supporting pipeline safety. It extends the scope of previous rules and regulations, and calls for the confirmation of MAOPs and material verification requirements.
These demand the implementation of comprehensive integrity management programs that focus on threats to pipeline integrity, including corrosion and cracking. Additionally, they demand steps to remedy these threats. This is part of a broader effort to ensure that no pipelines suffer compromise to their integrity and that safety is ensured as much as possible.
The major responsibilities for the industry will reside with asset owners and corrosion professionals alike:
- Asset owners need to improve integrity management and the management of change, which increasingly involves implementing routine monitoring and maintenance programs. This requires in-line pipeline inspection and the retention of inspection data to substantiate their efforts in pipeline safety.
- Corrosion professionals need to ensure the safe operation of cathodic protection and a greater awareness of the repair criteria for pipelines with cracks and corrosion.
Overall, this will increase opportunities for those working in the corrosion industry.
The Future of Pipeline Safety
The pipeline industry has a long history of accidents and safety issues. Their tragic consequences still affect workers, communities, and the environment to this day. However, the implementation of the PHMSA Mega Rule marks a significant turning point in addressing current and potential risks.
The mandates for stricter operational safety, improved monitoring, and comprehensive data reporting present a much-needed framework to modernize and enhance the safety of gas pipelines. As the industry adapts to these regulations, the hope is that the number of risks and incidents will greatly decrease. This will ensure safer operations and better protection for all stakeholders involved.