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Pipeliners Podcast host Russel Treat welcomes back Marc Lamontagne of the Lamontagne Pipeline Assessment Corporation for an important discussion on pipeline integrity, as it relates to the 2019-2020 NTSB “Most Wanted List.”

In this episode, you will learn what NTSB is recommending to PHMSA in regards to pipeline inspection, integrity management, and pressure testing. Within these topics, you will learn about very complex issues that are in the early stages of being dropped into a regulatory framework. Listen for what you need to know right now to stay ahead of the curve.

NTSB “Most Wanted List” for Pipeline Integrity: Show Notes, Links, and Insider Terms

  • Marc Lamontagne is the president of the Lamontagne Pipeline Assessment Corporation. Find and connect with Marc on LinkedIn.
  • NTSB (National Transportation Safety Board) is a U.S. government agency responsible for the safe transportation through Aviation, Highway, Marine, Railroad, and Pipeline. The entity investigates incidents and accidents involving transportation and also makes recommendations for safety improvements.
  • Integrity Management (Pipeline Integrity Management) is a systematic approach to operate and manage pipelines in a safe manner that complies with PHMSA regulations.
    • CFR 192 and 195 provide regulatory guidance on the pipeline transport of natural gas and hazardous liquids, respectively.
    • HCA (High-Consequence Areas) are defined by PHMSA as a potential impact zone that contains 20 or more structures intended for human occupancy or an identified site. PHMSA identifies how pipeline operators must identify, prioritize, assess, evaluate, repair, and validate the integrity of gas transmission pipelines that could, in the event of a leak or failure, affect HCAs.
  • Hydrostatic Pressure Testing is a method to use pressure to evaluate the strength of a pipe and determine the presence of leaks.
  • MAOP (maximum allowable operating pressure) was included in a bulletin issued by PHSMA informing owners and operators of gas transmission pipelines that if the pipeline pressure exceeds MAOP plus the build-up allowed for operation of pressure-limiting or control devices, the owner or operator must report the exceedance to PHMSA on or before the fifth day following the date on which the exceedance occurs. If the pipeline is subject to the regulatory authority of one of PHMSA’s State Pipeline Safety Partners, the exceedance must also be reported to the applicable state agency.
  • IVP (Integrity Verification Process) or HL IVP (Hazardous Liquid Integrity Verification Process) is a recommended test being developed by PHMSA. The goal is to evaluate the integrity of gas transmission lines to ensure conformity to MAOP when pipeline records are not traceable, verifiable, or complete.
  • ILI (Inline Inspection) is a method to assess the integrity and condition of a pipe by determining the existence of cracks, deformities, or other structural issues that could cause a leak.
    • Pigging refers to using devices known as “pigs” to perform maintenance operations. This tool associated with inline pipeline inspection has now become known as a Pipeline Inspection Gauge (PIG).
  • CP (Cathodic Protection) Verification is a test to reduce the corrosion of a metal surface by making that surface the cathode of an electrochemical cell. [NACE Standard TM0497-2012]
  • Weldment is a new part that is formed out of two separate parts. In pipelining, the new part must be carefully evaluated for integrity to ensure safe transmission of material through the pipeline.
  • Cracks in pipeline inspection refer to breaks, splits, flaws, or deformities in the surface of a pipe. Inline inspection tools are used to evaluate the severity of the crack.
  • Corrosion in pipeline inspection refers to a type of metal loss anomaly that could indicate the deterioration of a pipe. Inline inspection techniques are used to evaluate the severity of corrosion.
    • Corrosion holiday testing is a non-destructive test (NDT) used to detect premature corrosion in order to address the condition of the pipe in a timely manner.
  • The PRCI (Pipeline Research Council International) is the preeminent global collaborative research development organization of, by, and for the energy pipeline industry.
  • NPMS (National Pipeline Mapping System) is a dataset containing locations of and information about gas transmission and hazardous liquid pipelines and Liquefied Natural Gas (LNG) plants that are under the jurisdiction of PHMSA.

NTSB “Most Wanted List” for Pipeline Integrity: Full Episode Transcript

Russel Treat:  Welcome to the Pipeliners Podcast, episode 65, sponsored by EnerSys Corporation, providers of POEMS —  Pipeline Operations Excellent Management System, compliance, and operations software for the pipeline control center. Find out more about POEMS at enersyscorp.com.

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Announcer:  The Pipeliners Podcast, where professionals, Bubba geeks, and industry insiders share their knowledge and experience about technology, projects, and pipeline operations. Now your host, Russel Treat.

Russel:  Thanks for listening to the Pipeliners Podcast. I appreciate you taking the time, and to show that appreciation, we are giving away a customized YETI tumbler to one listener each episode. This week, our winner is Christopher Henkhaus with Chevron Pipeline. Christopher, your YETI is on its way.

Well, several weeks ago, I did a podcast on the NTSB’s Most Wanted List. I said I was going to find somebody to come and talk to us about the details on the integrity management side. Today, we have back with us Marc Lamontagne to elaborate on the NTSB’s Most Wanted List as it relates to pipeline integrity issues. Marc, welcome back to the Pipeliners Podcast.

Marc Lamontagne:  Thank you, Russel. It’s great to be back again. Hope all has been well since our last conversation.

Russel:  Life is full, in the abundance of all that that means.

[laughter]

Russel:  Yeah, it’s all good. It’s all good.

Marc:  Great.

Russel:  Thanks for coming on. I did an episode a few weeks ago about the NTSB and their Most Wanted List. I said I was going to get somebody who knows about pipeline integrity to come on and talk. Some of these things in particular are just outside my knowledge. I thought they might be inside of your knowledge. With that being said, why don’t we just dive in? I know you did a little research to prep for this. Do you have anything you want to say in advance?

Marc:  I’ll give it my best shot here, to try and characterize what the NTSB is looking for. I note that the NTSB’s recommendations are primarily towards PHMSA, with a couple towards state regulators, and a few towards companies, as well, but it’s industry-wide improvement on safety I believe is what the focus is.

Russel:  I actually made a comment in the last episode because a couple of these recommendations are actually targeted to a vendor.

Marc:  Yes.

Russel:  The first one I wanted to talk about is the need to hydrostatically test. There’s two items here, one is P-11-14 and the other one is P-11-15, that talk about hydrostatic testing.

One being the elimination of the grandfather clause for things constructed before 1970, and the other being a mechanism to determine a pipeline is stable if there is a construction defect. Maybe you can talk a little bit about the genesis of those and where they’re at?

Marc:  As a result of the failure that happened just prior to 2011, NTSB was looking at the strength of materials with respect to gas transmission pipelines. Within the part 192, CFR 49 192, there is this grandfather clause basically stating that if a pipeline was hydrostatically tested before 1970, that it could use that as its maximum allowable operating pressure, MAOP.

Due to that failure, they’ve suggested that all gas transmission pipelines constructed prior to 1970 be subject to a hydrostatic pressure test that incorporates a spike test to verify its strength.

In response to this suggestion — or recommendation — by the NTSB, PHMSA has been working on developing what is referred to as an Integrity Verification Process. This will hopefully address the testing requirements by proving material strength within the subject pipelines, as well as other information such as inline inspection information, CP verification, etc.

Russel:  Right. A lot of this comes out of old pipe and unpiggable pipe where there may have been a previous hydrostatic test, but it’s old. Is that correct?

Marc:  Pre-1970. Not necessarily unpiggable, but pre-1970s construction.

Russel:  Why 1970?

Marc:  That was a cut off, I believe, with respect to the vintage pipeline properties versus more recent pipeline properties.

Russel:  I guess that makes sense. [laughs] There’s a gentleman by the name of KC Yost who sometime comes on and talks about the history of pipelining, and how things were done way back in the ’30s, 40s, and ’50s.

I think that probably there was a fairly significant shift around that time frame from the old school way of pipeline, to a more modern approach, more of a strength of materials and a materials management approach versus get it in and get ‘er done. [laughs]

Marc:  I think you can say that for both the manufacture of the pipe as well as the pipeline construction techniques. Yeah, definitely.

Russel:  That’s a nice segue to 15, because it talks about what happens when there’s a known manufacturing defect. This is one of the words that I’d like to understand a little better. It says that, “Manufacturing, construction-related defects can only be considered stable if you do a post construction hydrostatic pressure test.”

What is a manufacturing related or a construction related defect, first part of the question, and what makes it stable versus unstable?

Marc:  That’s the monikers in play. The manufacturing defects are those imparted into the steel plate and pipe during the manufacturing process, such as scabs, which may cause a volumetric type anomaly, or laminations caused from impurities that are lengthened in the rolling process. Those would be known as manufacturing.

Construction related defects of course happen during construction, and could be some question with respect to weldment at the girth welds and potential repairs of such things as that. Those would be the type of defects referred to in this P-11-15.

Stability, these are considered stable defects as opposed to growing defects, considered that these were imparted on the pipe during manufacturing or construction, and not there as a result of a corrosion cell which is actively growing the defect. These are manufactured, construction, and coated, and not a growth anomaly.

Russel:  I guess the simplistic takeaway would be that if I have these known defects and I can hydrostatic pressure test 1.25 times the MAOP, then I can consider that good pipe.

Marc:  Yes.

Russel:  If I don’t do the test, I can’t consider it good pipe.

Marc:  Yes, and that’s what the implication is from NTSB. These can be monitored as well through inline inspection, considering them to have an appropriate coating, an appropriate cathodic protection. As I say, these can be monitored over time to ensure that no growth is taking place.

Russel:  That’s a good point because this is all about fit for initial service versus ongoing O&M [operations and maintenance]. This next one is going to be fun. [laughter]

Marc:  March to it.

Russel:  We’re probably going to spend a little bit of time talking about this one, but this is the recommendation P-12-003. It’s talking about cracks and engineering assessments when cracks are interacting with corrosion and what do you do about all that?

I know this is an extraordinarily complex topic, so maybe you can talk to us about, what’s the state of the art in terms of how was this being done before this recommendation came up? How is it being done now or what’s the process that’s occurring or discussion around this subject?

Marc:  As typical with NTSB recommendations, they usually come about due to a pipeline incident. This is a revision that they’re suggesting to the Code of Federal Regulations with respect to Part 195 of the liquids pipelines. What it basically would like to do is create and/or modify and clearly state how engineering crack assessments should be done.

It’s considering any type of crack defect including stress corrosion cracking, tow cracks, and as they note, environmentally assisted cracks, which are sometimes comparable to stress corrosion cracking.

They want to cover the gamut of cracks, which could include circumferential cracking as well, and then acceptable methods for performing these engineering assessments.

Of course, crack assessment is a sort of a niche subject, and there are many pipe properties as well as potentially external influences that affect the assessment of these defects to ensure their acceptability.

Beyond just methods for engineering assessment, the NTSB is also requiring specific criterias for acceptance of the crack defect and excavation timelines. That covers the excavation timelines of course must be made to be within an estimated crack growth for these various features.

Not only that, in the meantime, appropriate pressure restrictions must be imposed so in order to have appropriate pressure restrictions. The engineering analysis must look at the remaining strength of these crack anomalies to determine an appropriate pressure restriction.

If it is proposed to leave and monitor cracks within the system, then of course knowledge of crack growth, of fatigue, and any other stresses that are imparted on the pipe must be well known, documented, and considered in this engineering assessment. That’s the overall process that the NTSB wants included in Part 195, and clearly stated.

Russel:  To me, that sounds problematic. I would assume that historically, this has been, I would characterize it as engineering art. It’s learned over time, versus engineering specification. It sounds like what PHMSA is pushing for, what the NTSB is pushing for is more engineering specification versus engineering art.

Marc:  Right. Definitely there are some guidelines provided in a couple or a few different standards that can be referred to, but if the CFR becomes too prescriptive, then that may actually impair proper engineering assessments. It’s a fine line of course for such a…

Russel:  [laughs] That’s exactly what I was thinking is, how do you draw that line?

Marc:  Fortunately, there are these standards that can be referred to, there is software that can be utilized, and then of course, every year, more knowledge is gained on appropriateness of crack defect assessment. Yes, it is a good thing to have defined, but again…

Russel:  You got to be careful how you define it because the amount of discovery, and no two issues are exactly the same, so it does cause complexity.

I know that, oh gosh, it’s been a while back now, but we had a conversation with Cliff Johnson about PRCI and their data sharing initiative, trying to create a repository that can be used for research and assessment, and take and apply analytics.

This is one of those cases where a strong analytics engine could be extremely helpful, I think, in that it helps the engineer to get to what really needs to be an engineering judgment, versus just the rigor of getting through all the math to get a number out.

I don’t know. This one, to me, I’m always a little amazed that things this technical actually make their way through a regulatory rule-making process. I’ll just say it that way. This one is pretty dicey.

Marc:  That’s awfully difficult, yes.

Russel:  I think the next thing in this list that applies is the P-15-010, which is update guidance related to interactive threats. It’s talking about operators and inspectors on evaluation of interactive threats. I think the first thing would be, let’s define, or maybe you could define for us what an interactive threat is.

Marc:  Sure. Interactive threat, as it implies, are multiple defects, two or more that occupy the same location and space on the pipe, and so therefore they interact.

Russel:  I have a dent, and I have corrosion, and they’re at the same place.

Marc:  That’s correct. Typically, if you have two or more defects that occupy the same space, this will obviously affect somewhat the remaining strength of the pipeline and requires assessment.

Russel:  Right. What’s NTSB trying to get PHMSA to do here?

Marc:  NTSB is recommending that PHMSA update guidance for gas transmission pipeline operators and PHMSA inspectors on the evaluation of interactive threats. One obviously is to update the CFR to discuss a little more the threat interactions, and the evaluation and acceptance methods to be used on these threat interactions.

Again, it’s stepping into an area that is sometimes a little gray and may require engineering assessment, which is similar to the crack evaluations that we just mentioned, and could include crack evaluations such as crack in corrosion and of course that adds complexity to the assessments.

PHMSA has mentioned that they intend to enhance and expand the minimum requirements for performing threat identification and address standards for the data sets used, data validation, integration, and also consider subject matter expert bias. I’m not exactly sure what the subject matter expert bias refers to here.

Russel:  Man, that’s exactly the next question I was going to ask. You’re heading me off at the pass.

Marc:  [laughs] Wondering about that, I can understand data bias but I’m not sure what PHMSA would write about SME bias.

Russel:  I think I could speculate a little bit. This is just a pure guess but, to me, when you’re operating as an engineer and you’re working in a discipline, and this is true in a lot of engineering disciplines. There’s what you learn in university and then there’s what you learn in the world, and they’re not the same subject matter.

What tends to happen is, if you practice in a narrow area, through your experience, you develop a certain bias that informs and influences what you see and what you do based on what you see. The problem with that is that that can be inconsistent within engineers in a company, it can be inconsistent within companies.

For a regulatory authority, that inconsistency is difficult to inspect. By providing guidance and creating some rules, what you’re hoping to do I would think would be to get everybody on the same page about, “Here are the things that matter, and here is how we’re going to look at them.”

Marc:  That sounds reasonable. I’m unsure as to how in depth they’re going to be with this threat interaction guidance.

Russel:  I think it will be to be very difficult to be very in depth.

Marc:  That’s it. More than just identifying potential threat interactions, it would be difficult for them to specify how to evaluate and which acceptable method to be used.

Russel:  I think it could also potentially increase risk.

Marc:  Yes, that’s true.

Russel:  There are so many variables that the more I tighten down my process, the more likely I am to miss something material.

Marc:  Right. Very much so.

Russel:  It’s the higher order asking the, “What could I be missing?” question that becomes difficult when you start over-specifying.

The next one here is 15-11 and its own risk assessment, training for inspectors and verifying the technical validity of risk assessments that operators use. The first thing is, what does risk assessment mean in this context?

Marc:  If you look at actually both 15-11 and 15-13, they’re both with respect to risk assessment. 13 goes on to say that guidance should be created which includes methods for setting weighting factors for the risk assessment, factors that should include consequence of failure calculations as well as appropriate risk metrics and methods for aggregating risk along the pipeline.

Those at a high level are the important measures to create the risk assessment within each pipeline. These two recommendations together want to not only develop specific risk assessment guidance and variables, but also implement specific training for PHMSA inspectors so that they can verify operators’ risk assessment methods and models.

Russel:  Again, that sounds very non-trivial.

Marc:  I believe it would be very difficult to put down on paper with enforcement in mind, so yes, I would agree.

Russel:  That leads into the next one, which is 15-017, which is talking about, evaluate the relationship, develop a program, so this is instructing PHMSA to develop a program to use data that’s collected in other recommendations in order to evaluate inappropriate threat elimination, interactive threats, and risk assessment approaches.

This is one of those things that you get like one paragraph or one long sentence maybe that’s a recommendation that I have no idea the R&D program that will be required to do something meaningful with this.

Marc:  The creation of the Part 192 and 195 for integrity management was primarily based around high-consequence areas, and removing the anomalies and threats within these high-consequence areas.

As part of this 15-017 to assess the areas with respect to the threats and risk assessment approaches, they not only have to consider risk assessment models and operators knowledge, but are actually going back to National Pipeline Mapping System as well to help industry and inspectors to identify where high-consequence areas are, and what potential interactions may occur with not only pipeline operating conditions, but public in these areas.

Russel:  Right. Moving along through the list here, the next thing that they’re talking about is this 018, which is, there are several things here that are around unpiggable lines and direct assessment and elimination of operating conditions that prohibit effective ILI runs.

I’m bundling several of these together here. I’m wondering maybe you can elaborate a little bit on what’s happening here, and what are the things that maybe the listeners should be thinking about in this context.

Marc:  Sure. Some older pipelines are considered unpiggable simply because they may have bends that are too tight in radius to allow inline inspection tools to travel through, or valves that don’t allow for the passage of an inline inspection tool because of its smaller diameter, for instance.

These suggestions by the NTSB all discuss uninspectable pipelines and what should be done. One, they’re considering of course upgrading old pipelines if it’s possible, removing unpassable items such as smaller valves, tight bends, replacing them with the ones that inline inspection tools can pass through.

Also, putting language into the CFR such that new pipelines that are being built will obviously be able to allow inline inspection tools to go through. Beyond that, as you noted, 15-021 talks about eliminating the use of direct assessment as the sole integrity assessment method for gas transmission pipelines.

Direct assessment is basically an above-the-ground method to examine the buried pipeline and determine where corrosion holidays exist and therefore potential active corrosion features.

What they’re saying here is that even though that process may provide valuable information, they believe that it should not be used on its own and should be combined with other measurement technologies such as inline inspection to further the operators’ knowledge.

Russel:  I think one of the things that I’m learning just as I read various trade publications and such, is the idea of corrosion. Looking at corrosion as a primary mechanism of failure is no longer acceptable, that looking at dents and cracks, and in particular, interactions of dents, cracks, and corrosions is what’s required.

Marc:  That’s right. There’s a gamut of threats that may or may not be innocuous to a pipeline system. Of course not all pipeline systems are created equal and the environment they’re in, the material that’s used, the product it ships, all those variables.

Russel:  The soil that it sits in, the nature of the terrain, the water table, all those things play into it.

Marc:  Exactly. In all these suggested paragraphs, the risk assessment, the piggability of the pipe, the methods used to evaluate threats, it’s all very dependent on many external causes.

There are just so many variables within it that pipeline operators of course have to consider all these, and so it’s difficult to specify directly within regulatory environment how an operator should handle their system.

Russel:  In the flip side of that is, and yet the public has a reasonable expectation of pipelines operating with due care, and using appropriate and current technology and approaches for doing all these things. I think sometimes people don’t realize just how complex this is. Not even people actually doing the work, sometimes I don’t think they realize how complex it is.

You tend to take for granted because what we do is really pretty dang advanced, it’s easy to take for granted the part that we don’t know.

Marc:  Yes.

Russel:  I’m going to wrap up here, and we’re going to talk a little bit about dents. This goes to 17-001 and 002 and some others, but it says the recommendation is, work with organizations to modify the dent acceptance criteria to account for all the factors that leave for failure.

I think what’s interesting about this is really, what is a dent acceptance criteria? What are all of the things that cause failure, particularly those things that would cause the NTSB to write this kind of item?

Marc:  This is known to be a criteria that is limited and not considering all substance of dents. As seen by industry, there have been incidents that this criteria did not cause repair.

Russel:  Didn’t catch the defect before there was an incident.

Marc:  Yes, that’s right. Therefore, the NTSB of course is asking to modify the dent acceptance criteria, so dents not only are described by their depth, but also any other interactions that are involved with other defects.

The strain on the pipes or external forces may cause issues, the cyclic fatigue of the liquid inside, just various other operating parameters can lead to a dent failure.

Russel:  I’m even thinking about something as simple as even if there’s not interactions, the nature of the geometry of the dent can matter.

Marc:  Definitely. There are sharpness variables with respect to its indentation shape…

Russel:  Anybody who works around metal knows that if it’s a round corner versus a sharp corner, it behaves differently.

Marc:  Yes, and even if it’s sitting on a rock as opposed to where it is held in place by the rock, or whether the dent is able to flex with the pressure within the pipes. It’s more than just the depth, which has typically been the guidance given by regulations.

Russel:  This kind of conversation, to me, Marc, is always fascinating. I always learn when I talk to you. [laughs] I often walk away with my head hurting a little bit. This might be one of those situations.

I’m thinking about these recommendations, and while they all make sense, I know enough to just have a clue about the complexity and difficulty of implementing this type of thing in a regulatory framework.

Of course, we are called to do that, I think. It’s part of our fiduciary responsibility as pipeliners to try to figure out how to do things better, and where safety is involved, share that with the industry so that others can do it better as well.

This is helpful. There is no way I could have had this level of depth in conversation about these most wanted items for the NTSB without your help. Thanks for your participation and expertise, and it’s a pleasure to have you here as always.

Marc:  I think you’re too gracious, Russel. Thank you.

[laughter]

Russel:  Thanks. I hope you enjoyed this week’s episode of the Pipeliners Podcast and our conversation with Marc Lamontagne. Just a reminder before you go, you should register to win our customized Pipeliners Podcast YETI tumbler. Simply visit pipelinerspodcast.com/win to enter yourself in the drawing.

If you would like to support this podcast, you can do that by leaving a review on Apple Podcast, Google Play, or whatever smart device podcast application you use. You can get instructions at pipelinerspodcast.com.

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Russel:  Finally, if you have ideas, questions or topics you’d be interested in, please let me know either on the Contact Us page at pipelinerspodcast.com, or reach out to me on LinkedIn. Thanks for listening. I’ll talk to you next week.

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