February 2020, Vol. 247, No. 2
Features
Pipeline Integrity Management – Past, Present, Future
By Richard Nemec, Contributing Editor
Before what was once a quiet middle-class suburban neighborhood in San Bruno, Calif. had cooled into silence, a decade-long response in the U.S. pipeline industry was already underway, focusing on the molecules making up modern large-diameter pipe and the densely populated areas in which these energy highways traverse.
In 2020, the industry is preparing to turn the page from that tragic natural gas transmission pipeline rupture in 2010 that killed eight residents and injured 51 others while destroying or damaging more than 100 homes two miles west of the San Francisco International Airport.
In the aftermath, federal investigators found that “among several causal factors the operator, San Francisco-based Pacific Gas and Electric Co. (PG&E), had an inadequate integrity management (IM) program that failed to detect and repair or remove the defective pipe section,” the National Transportation Safety Board (NTSB) stated in the Federal Register last fall.
Allegedly, PG&E at the time was basing its IM work on “incomplete and inaccurate” pipeline information, leading to inaccurate risk assessments for the pipe segment. NTSB investigators concluded that as a result PG&E’s IM program “resulted in no meaningful improvement in the interest of its pipeline systems.”
In addition, two years later on Dec. 11, 2012, another rupture in a gas transmission pipeline operated by Columbia Gas near Sissonville, West Virginia, added to the regulatory conundrum when escaping high-pressure gas ignited and fire damage was extended over nearly 1,100 feet (335 m) along the pipe right-of-way. There were no fatalities or injuries, but three houses were destroyed in the path of the fire that spread to more than 800 feet (244 m) in width. NTSB finalized its report on the Columbia incident in February 2014.
In the aftermath, the new federal rules are expected to be the start of a multiphase, multiyear transformation of how pipeline safety is implemented by the industry and overseen by regulators in the next decade, beginning with the implementation of the 2019 Pipeline Safety Improvement Act from Congress, in which the Department of Transportation’s (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA) is charged with carrying out.
The experts at national trade and research organizations, such as the Interstate Natural Gas Association of America (INGAA) and the Gas Technology Institute (GTI) expect second and third iterations of the PHMSA 2019 rule amendments.
Oil and gas operators are left with the suggestion that they “stay awake” and sensitive to how the new approaches are going to be implemented and impacted by their particular systems, all of which need to account for regional political, regulatory and internal operating differences.
“There is a broadening of scope” in the types of pipelines that fall under the PHMSA rules to include a lot of the oil/gas pipeline gathering infrastructure, according to Mike Adamo, GTI’s vice president of operations at Operations Technology Development (OTD), a 27-company nonprofit consortium supporting pushing the research envelope in the gas sector. “Companies are trying to determine how they will be impacted by the new rules, and what they need to change to comply,” Adamo said. “Procedures, inspection frequencies and more are all impacted.”
With an ongoing focus on data and IM, GTI provides an industry-backed resource for natural gas utilities that are facing multiple challenges in maintaining pipeline system integrity. If research organizations can help improve the accuracy of inspections and/or reduce costs through the development of new tools, methodologies and technologies, industry safety standards can be enhanced, the GTI engineers contend.
“Industry needs to make data-driven, risk-based decisions for critical infrastructure to address risks and mitigate against problems,” GTI emphasizes on its website. “We are developing and evaluating technology, tools, protocols, models and training to help operators meet pipeline and distribution system integrity management requirements.”
At PHMSA, the new rule, or more technically amendments, to the regulations covering the Safety of Gas Transmission Pipelines published in October 2019 addresses Congressional mandates related to onshore gas transmission only and specifically do not cover gathering lines and distribution pipelines. In addition, the amendments include NTSB recommendations and various public input, including from the oil/gas industry. IM requirements and others are covered by the new regulatory dictates.
The new rules, to be effective July 1, focus on “actions an operator must take to reconfirm the maximum allowable operating pressures (MAOP) for previously untested natural gas transmission pipelines and pipelines lacking certain material or operational records, along with periodic assessment of pipelines in populated areas not designated as high consequence areas (HCA).
The changes also cover reporting instances of exceeding MAOPs, considerations of seismicity as a risk factor in IM, the safety features of inline inspection processes, a six-month grace period for seven calendar-year IM reassessment intervals and other related recordkeeping issues.
INGAA attempts to be a center for IM planning/review, safety lessons learned and interfacing with the national policymakers. The organization is geared up in 2020 to assist its member’s understanding to begin to implement the new PHMSA requirements for every stage of traditional high-pressure transmission pipeline operations.
“Natural gas transmission operators use specialized steel materials, thorough testing/inspection programs, state-of-the-art technologies, 24/7 monitoring and extensive training/qualification programs,” INGAA officials stress on the association’s website.
But IM stretches far more widely than the nuts and bolts of daily operations and integration of a safety-first culture, involving public safety outreach programs, emergency response planning and ongoing work with first responders, along with interacting with applicable federal and state regulators. INGAA and its members support the need for “rigorous safety programs and oversight” to ensure safe, reliable delivery of gas supplies.
Post-San Bruno and since 2011, INGAA has led the establishment of industry-driven enhancements to IM, approaching it as a “continuous improvement” program. INGAA leaders like CEO Don Santa contend that member pipeline operators “have made great strides” in advancing IM programs.
Examples include the advances since 2011 in the control centers serving as the eyes and ears of pipeline operators. These centers manage the nation’s pipelines using specialized equipment such as a supervisory control and data acquisition (SCADA) system.
While PHMSA is planning at least two more phases of amendments to its pipeline rules, the 2019 changes entail scaling up existing IM programs and applying them to a larger proportion of transmission pipelines, according to C.J. Osman, INGAA’s director of Operations, Safety and Integrity. The new requirements have a broader geographical application, expanding beyond the so-called HCA, or heavily populated areas.
Subsequent focus for PHMSA will dive deeper into the details of identifying and dealing with pipe corrosion, including the principles of IM and related federal requirements to gathering pipelines, since the shale gas boom has grown in size and importance for the industry.
“The amended rule is something the industry has been talking about for a long time, back to 2011 following San Bruno,” Osman said. “Back then, INGAA members committed to extending IM outside of just HCA geographic areas. And the decision to get started years ago leaves INGAA members in a good position to implement PHMSA’s rules.
“Through the public comment sessions as part of PHMSA’s developing the new rules, various time frames were set for implementing different parts, so they aren’t all expected to be implemented by the same date; they’ll be implemented over several years with different milestones along the way.”
Engineers throughout the industry and at its think tanks, such as Des Plaines, Ill.-based GTI, emphasize that the new PHMSA rules not only expand IM, but they also will expand the kinds and extensiveness of recordkeeping as well as pipeline material evaluations, along with requiring extensive, systematic reconfirmation of pipeline pressures or MAOPs.
The new rules provide new definitions of moderate consequence area (MCA), reaching beyond the narrower focus on HCAs, and for engineering critical assessments (ECA). “In some cases, some portions of an operator’s pipelines are not going to have adequate historical data, and they will be faced with some choices as to whether they have to directly assess those lines, or would it be OK to get information through some engineering means that are now allowable to comply,” said GTI’s Tony Lindsay, managing director for Energy Delivery.
Lindsay emphasizes that GTI’s programs for helping operating companies better understand the new rules are divided among three main areas: (1) the need to reconfirm the MAOP on grandfathered or “legacy” lines that were previously exempt from pressure confirmations, (2) expanded requirements and new definitions impacting which lines fall under the rule, and (3) better definitions and clarity on what records need to be maintained.
In response to the individual operator, pipeline and topography types need to have the correct and most advanced tools. It is more critical for IM programs under the latest federal rules and requirements. GTI considers itself well equipped to help in this area and does regularly with a number of ongoing projects. Leak identification and correction, the application of ECA, modeling of steel cracks and better understanding of materials and how they react to different environments are all part of the GTI playbook.
“There is modeling on how steel will crack before bursting, or how a crack will propagate at various pressures, the strength of different materials, and other models that correlate what can be measured on the surface of the pipe,” Lindsay said. “These are all things we have worked on in the past, and they are coming into play.”
Regulators now recognize that ECA is another way to gauge the level of integrity in a pipeline, according to the GTI engineers. A whole modern history of the energy pipeline industry has been written since federal regulators decades earlier exempted pre-1971 pipelines from the PHMSA rules as part of a grandfathering clause applied back then.
Fast forward to 2019, and today’s new rules aim to pull in all of those exempted lines. The new rules eliminate the past exemption, including a lot of recordkeeping and reporting that the operators of those pipelines now will have to provide.
Those previously exempt pipelines need to reconfirm their MAOPs and to have an understanding of the chemical makeup of the steel pipe that was not required previously. Operators can perform hydrostatic tests or do an ECA to verify the pipeline’s maximum pressure.
A key to the future under the broader PHMSA rules is the adaptation that IM work since San Bruno has reaped, such as the ability to apply some of the same technology that has worked with large-diameter pipelines to smaller-diameter pipes in unconventional configurations. GTI is helping do that through the “e-mat” technologies, electro-magnetic acoustic technology that can handle pipes as small as 8 inches (203 mm) in diameter.
In another area, GTI has worked to find ways to regentrify old, cast iron pipelines that typically are replaced in the 21st century.
While the 2019 PHMSA rule really applies mostly to transmission pipelines, cast iron is still an integrity management issue for distribution pipe operators, the GTI engineers emphasize. And while the industry takes the position of replacing cast iron, Lindsay noted that the industry is considering a future time when the last few miles of cast iron could be too costly or logistically impossible to replace for any operator.
An advanced research project team at the U.S. Department of Energy (DOE) wants to assemble a group to develop “an internal inspection and repair robot” technology to be able to restore the useful life of those last miles of old low-pressure cast iron mains.
According to Lindsay, DOE hasn’t yet released the proposal for bidding, but in 2020 it may begin to come to life. “GTI may look to partner with some others in the industry to respond to the expected DOE bidding request. So far, the proposed project is labeled simply as “repair.”
Two terms that the new PHMSA rules will evoke are “data-driven” and “risk-based,” because they are embodied in the new rules and should be found in the latest IM operating plans.
For a number of years, GTI has invested a lot of money through Operations Technology Development (OTD) or OTD-E in partnership with PHMSA seeking to better understand risk while looking for more effective ways to assess it.
“PHMSA seems to be moving toward driving operators from understanding the ranking of risk to a more quantitative and ultimately more probabilistic understanding of risk where you can assign percentages for the likelihood of events happening,” Adamo said. “So, an operator can more accurately categorize the context of things happening, and you can approach repairs in a way that minimize the risk according to the dollars being spent [versus just replacing lengths of pipe].
“All distribution integrity management is really about knowing your system, knowing where your leaks are, and having detailed information on the types of materials in your pipes, and so they have lots of data on leaks, what caused them, and they can then analyze that data to make decisions on replacing or repairing.”
The current trend toward “big data” has spread into the IM space, and GTI has pursued various projects to refine “enterprise decision support systems” (EDSS), allowing data to be pulled from multiple sources, and it definitely is gaining traction among utilities, Adamo said. Utility distribution system IM planning, as well as transmission/storage operations, now live in the big data world.
Advanced technologies with more sophisticated data are used to assign levels of risk to various distribution and transmission pipeline systems, as well as the broader risks that the overall corporate organization assumes.
Over the years, GTI has developed various risk assessment models for specific types of equipment, ranging from cast iron to plastic pipe, and it is now focused on rolling that modeling into one enterprise-wide model for risk decision-making. “This is where a lot of the GTI effort is going now,” Lindsay said.
Adamo said the challenge now is to help standardize and integrate the past work into a model that works for steel pipe, which is more complicated in terms of its material test reports (MTR) coming from the pipe manufacturers.
“You need to develop a bar code that will stand up throughout the life of the product,” Adamo said, noting that GTI is seeking bar codes and accurate tracking of pipe all the way back to the mill. That is part of the new PHMSA rule requirements.
Data and IM are a core focus at GTI, according to the organization’s leaders. GTI is developing and evaluating technology, tools, protocols, models and training to help operators meet pipeline and distribution system integrity management requirements, they contend on the organization’s website.
Cast Iron Replacement
To help operators make monitoring and repair decisions, as well as prioritize their replacement programs, GTI experts developed a cast iron fitness-for-service (FFS) model, calculator and method. DOT’s PHMSA effort has helped operators characterize and grade graphitic corrosion defects on cast iron natural gas pipe.
This FFS guidance is critical to ensure safety and stability of natural gas supply. In a 200-page report, GTI validated engineering guidance to identify and prioritize the highest risk piping for replacement programs. It is a virtual guidebook on properties, metallurgy and corrosion characteristics of cast iron used for natural gas distribution systems.
Hydrogen Blending
GTI considers its work as leading the support for gas pipelines’ safety and reliability. It claims to have leveraged this expertise to assess the impacts of injecting hydrogen into the North American natural gas pipeline infrastructure network, something that has been studied throughout the post-World War II era.
This work covers all aspects of material and component performance compatibilities with varying degrees of hydrogen in the pipeline. GTI has completed in-depth hydrogen blend studies for a consortium of natural gas operators, as well as the U.S. National Renewable Energy Laboratory (NREL).
GTI and other industry sources have thick playbooks that will help operators face the new realities at PHMSA, covering risk assessment models for everything from vintage plastic pipe to microbiologically influenced corrosion (MIC) in gas storage operations. It appears there is no shortage of tools, but the trick will be to find the right ones for each given IM application.
Utilities and GTI are collaborating on a regional basis to develop a quality audit program for gas utility operators with a mechanism to collectively audit their supplier’s quality management systems. The program will conduct an independent and unbiased assessment on behalf of participating operators to provide a reliable and standardized approach for monitoring suppliers.
GTI audits select suppliers using ISO 9001, industry standards and company-specific requirements. The identification of threats and mitigating risks starts with the manufacturing process.
A hydrotesting alternatives program at GTI has identified and ultimately validated technologies that can provide an inspection that is “equivalent to – or superior than” – a hydrotest to obtain regulatory acceptance. With OTD funding, GTI developed and deployed a “critical flaw-and-critical wall loss” calculator that can help ensure pipeline safety and provide operators with significant cost savings in complying with new regulations.
The model allows operators to determine if an inspection technology could detect a crack-like flaw and/or wall loss that would fail a pressure/hydrotest at a particular pressure. It helps enable operators to use the engineering approach, ECA, in lieu of a hydrotest that requires shutdown and water injection.
It is this sort of focus on prevention in the context of the longer range future that the industry will need in the coming years of the 2020s to underscore its relevance and essential usefulness for the future. By the end of this new decade, the integrity of every energy-carrying pipeline in the United States should be well-known and well-documented.
“There has been a lot of focus recently on pipeline safety management systems,” INGAA’s Osman said. “Looking at pipeline systems through that lens can help the industry continuously raise the bar. It really is an ‘all-of-the-above’ approach to looking to whether you have the right process, right people and right technology being used. All of that is going to factor into the equation.”
Is the oil and gas space adequately ready for the challenge of broader PHSMA rules?
“Yes, absolutely, our data shows we’re making progress,” Osman said. “Our goal is very clear – a perfect reliability and safety record.”
Richard Nemec is P&GJ’s Los Angeles-based correspondent and a regular contributor. He can be reached at rnemec@ca.rr.com.
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