December 2024, Vol. 251, No. 12
Features
Looking at Post-TIMP Future for Pipeline Development
(P&GJ) — The Transmission Integrity Management Program (TIMP) final rule, established by the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA), was developed in response to several tragic pipeline incidents. 49 CFR Part 192, Subpart O, mandates that natural gas pipeline operators implement a risk-based integrity management plan.
Focusing on high-consequence areas (HCAs), the rule requires regular pipeline assessments using methods like in-line inspection, pressure testing or direct assessment. TIMP emphasizes continuous monitoring, threat mitigation and documentation to ensure pipeline safety, reduce failure risks and protect public and environmental health.
The TIMP rule, which went into effect on Dec. 17, 2004, outlined four key objectives aimed at enhancing pipeline safety. These objectives included mandating operators to establish integrity management programs for gas transmission pipelines in areas where a leak or rupture could cause significant harm, particularly in high-consequence areas (HCAs).
In addition, operators were required to conduct ongoing assessments of pipeline integrity to improve data collection, integration and analysis, as well as carry out repairs and remediation as needed and implement preventive and mitigative actions.
Key TIMP Objectives
Perform Ongoing Assessments of Pipeline Integrity: While individual operators always put long-term system improvement programs in place, they were mainly focused on capital projects. In 2004, identifying, scheduling and planning for operations and maintenance (O&M) activities years in advance was a new concept for most operators.
Although pressure testing and direct assessment methodologies are still in wide use, ILI has grown in popularity. One of the key advantages of ILI is its ability to gather data about the entire length of the segment from launcher to receiver. As such, anomalies both within the targeted HCA as well as the rest of the line are identified.
In-line inspection (ILI) was not as common as it is today, despite the fact that technology had already improved significantly in the years leading up to the rule. The challenges of successfully passing an ILI tool through a pipeline with unknown bends, tees and other features was not an easy task. However, the pipeline industry has never been one to shy away from a challenge.
For example, the inaugural Unpiggable Pipeline Solutions Forum was held in 2011, and in less than 10 years, it evolved into Pipeline Pigging and Integrity Management (PPIM) conferences, reflecting our industry’s advances and can-do attitude toward difficult-to-pig lines.
Today, nearly 90% of integrity assessment mileage uses ILI. Reaching this stage, however, necessitated numerous piggability studies, extensive retrofitting efforts and the installation of launchers and receivers. Additionally, operators anxiously monitored each tracking location, carefully measuring the time until the pig passed through, while hoping it would not become lodged within the pipeline.
Several developments conspired to make the use of ILI in integrity assessment possible. Firstly, modern pipeline design practices evolved to enable the passage of ILI pigs. Secondly, critical advances were made to the design of the pigs themselves, in terms of form factor, detection limits and propulsion capabilities. Thirdly, increased usage of tools empowered service providers to expand their offerings to meet demand.
Looking forward, the industry anticipates ever-increasing application of ILI methodology. Advances in detection capabilities, form factors and pipeline designs will enable more lines to be piggable. Advances in data analysis tools and methods may enable us to spot and act upon emerging conditions sooner than ever before.
Make improvements in data collection, integration and analysis: Data collection and retention practices in the early days of the rule were vastly different than what we typically see today. Paper records, handwritten forms and marked-up alignment sheets were not uncommon.
The major data governance decision back in 2004 was deciding whether the official record was the document filed in a field office or the copy that got mailed to headquarters. Scanning documents and attaching them to a centralized database posed legitimate electronic storage space concerns.
Today, all but the smallest operators employ some form of geographic information system (GIS) to map, monitor and manage pipeline assets and infrastructure. These systems often input directly into a risk model and mobile data capture speeds up data entry and minimizes transcription errors. Rapid data collection is increasingly being achieved electronically and mobile data acquisition will continue to grow in popularity and feasibility.
The process of HCA analysis was once highly manual and labor-intensive. Aerial imagery was not readily accessible, often requiring costly aerial surveys, followed by the tedious tasks of digitizing structure outlines, classifying those structures and adding occupancy counts where needed.
Determining the potential impact circle involved physically moving it along the pipeline centerline on a map. Today, advanced GIS-based tools have streamlined this process, enabling faster and more consistent HCA analysis. Even the review and approval stages have become significantly less labor-intensive.
Threat identification and risk models required by the rule have also come a long way. As the industry continuously drives toward more sophisticated tools, like probabilistic models, it is helpful to look back and see the stepwise advancements that have brought us to where we are today. By implementing those early risk models, operators found data gaps, like missing or unknown records.
Scoring missing or unknown data as “high-risk” incentivized operators to fill those gaps. This often prompted research into old files, cleanup of records and process improvements going forward. At the same time, information about the integrity of the pipeline was being generated through assessments and other measures.
Advances in GIS database and risk model tools coincided with this influx of data. As more data was entered into these systems, the more useful they became. Field personnel, who may have been leery of old mapping systems (as opposed to their personal knowledge or hand-sketches kept under their truck seat), began to see value in the new tools.
Eventually, data once used almost exclusively by integrity personnel for risk ranking of segments started getting widespread use in project planning.
Today, we are seeing evolution in both the data and analysis spaces. As analytical capabilities improve, so do data modeling and database storage methods. We are seeing emerging technologies that are enabling better insights between spatial and non-spatial data.
Spatial data, such as physical asset information tied to GPS-specific coordinates, has been the foundation of most integrity databases and risk modeling programs, combining that with non-spatial information, such as operational data.
With the evaluation we as an industry have already gone through — asset data collection, risk modeling — we will be able to build prescriptive models that allow us to make decisions to achieve a desired outcome or operational goal by changing something upstream. In the context of integrity management, which could mean risk reduction, assessment schedule optimization or continuous system improvements.
Repair and remediate the pipeline as necessary: By comparing results — particularly between ILI tool runs or direct assessments — operators are provided with the ability to calculate growth rates, better predict remaining life and schedule reassessments accordingly.
Currently, only 25%–30% of repairs in HCA’s that result from integrity assessment are an Immediate Condition. The rest are scheduled repairs. This indicates processes are effectively catching issues before they become too serious, allowing time to either monitor progression or at least plan for a future repair. Performing repairs, replacements and other remediation activities in a controlled fashion can improve efficiency, minimize downtime and decrease costs.
While average annual assessment mileage has more than doubled in the last 10 years, the number of anomalies found that require repair is trending downward (Figure 1). Similar trends can be expected for other assessment methods.
Integrity management practices, along with targeted infrastructure programs (e.g., cast-iron main replacements) and more recent maximum allowable operating pressure (MAOP) reconfirmation requirements have significantly reduced the number of older pipelines in operation. From 2004 to 2023, there has been a 38% reduction in pipeline mileage of unknown or pre-1950 vintage. Furthermore, hundreds of anomalies within HCAs are repaired or have their pipeline segment replaced or abandoned.
Implement preventive and mitigative actions: In the early days of the rule, threat identification often began with manual questionnaires. Stacks of forms had to be manually processed — one for each pipeline route — to create a comprehensive master list for the client, which would then be used for selecting preventive and mitigative (P&M) measures.
Risk scores were used to decide which threat or threats the operator wanted to focus on. In the early years, many operators reviewed their O&M procedures to identify practices that exceeded minimum code requirements, which they could then count as part of their P&M measures. As time went on, risk models became more robust, while more data types became available to populate them. Manual forms largely went away, but we were still stuck with the challenge of P&M measure selection.
With a few exceptions, P&M measure requirements are not very prescriptive. This flexibility is necessary to allow operators to utilize the best mitigation or prevention tools for their situations. There can be a dizzying array of choices.
Monitoring for Third Party Damage (TPD) and/or Outside Force Damage is one area where emerging technologies will continue to advance the pipeline industry. 20 years ago, the idea of drone patrols or satellite leak detection systems seemed impossible. Now, as these technologies become more feasible and practical to employ, it seems inevitable that the industry will one day adopt them as the new normal.
What happens when we start integrating data streams in real time? No more manually comparing ILI or ECDA results to pipeline crossing data or one-call tickets to identify which anomalies might be Third Party Damage. When the expense and environmental cost of fixed-wing aerial patrols can be replaced with cost-effective and carbon-neutral monitoring tools, we may be able to reliably find excavation activity near transmission lines before or while it is occurring, not after a line strike.
In our daily lives, weather alerts now reach our smartphones with remarkable precision. Similarly, this level of accuracy is expected to be applied to pipeline infrastructure data, enabling the rapid deployment of remote monitoring tools. Regulatory requirements, however, are likely to lag behind technological advances.
P&M measures are an ideal proving ground for the first application of new technologies, in tandem with existing methods. For example, instead of increasing surveillance frequency as a P&M measure, an operator may choose to perform standard patrol at prescribed levels and then utilize new technology off-cycle. Comparing mid- to long-term data trends can be used to justify the new technology’s equivalence. As the industry moves in this direction, regulations will eventually catch up.
As the volume of data regarding our assets increases and the data structures and analyses tools become more technologically advanced, we will eventually be able to take an even more detailed approach to P&M measure selection. When evaluating an anomaly or performing a root cause investigation, we will be able to harness AI to sort through volumes of contributing factors to identify similar segments.
Next 20 Years
It is impossible to measure the “what-ifs” of incidents that never happened because of the TIMP rule. But what we do know is that the industry has grown and adopted the mindset of continuous improvement, risk mitigation, and data-driven decision making to reduce risk and improve safety.
In the years since the TIMP rule, both distribution and storage IMP rules were put into effect. All three parts of the Mega Rule have been built upon foundations that started 20 years ago. Rupture mitigation valves (RMVs) have gone from a possible P&M measure to a prescribed requirement under very specific circumstances. Soon the industry will rise to the challenge of new pipeline leak detection and repair rules. With each iteration, we improve our energy infrastructure and advance public safety.
Whatever comes next, the lessons from developing and implementing integrity management will serve us well: define a goal, devise a plan, identify tools to implement it and then go out and do it. If tools or processes do not already exist, create them, and apply technology to make decisions that are more intelligent, faster and which have a better understanding of implications.
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