This week’s Pipeliners Podcast episode features Aaron Dinovitzer of BMT Canada discussing the keys to the successful adoption of API RP 1183 (Assessment and Management of Pipeline Dents) in pipeline operations.

In this episode, you will learn about various topics involved in API RP 1183, including its history, the different types of dents that can occur within a pipeline system, gaps that API RP 1183 aims to fill, and the many inline inspection and assessment tools that can be used to support the use of the Recommended Practice.

The conversation also covers the differences between PHMSA’s rulemaking and the recommendations in the RP about managing these variances. Finally, Aaron shares what he thinks all pipeliners should know about API RP 1183.

API RP 1183: Show Notes, Links, and Insider Terms

• Aaron Dinovitzer is a Vice President at BMT Canada. Connect with Aaron on LinkedIn.
  • BMT Canada evaluates the suitability or interaction of structures, degradation or damage, materials, and loading to support design, maintenance, and forensic investigations in industries such as oil and gas.
• API (American Petroleum Institute): Since its formation in 1919 as a standards-setting organization, API has developed more than 700 standards to enhance industry operations. Today, it is the global leader in convening subject matter experts to establish, maintain, and distribute consensus standards for the oil and natural gas industry.
  • API RP 1183 (Assessment and Management of Pipeline Dents) is a Recommended Practice that includes detailed technical discussion on dent formation, strain and fatigue, and failure modes and mechanisms. The information provides pipeline operators necessary knowledge to make informed integrity management decisions regarding the management of dents on their systems.
    • Access this API Webinar on API RP 1183. (Note: you must be logged into API’s Learning Management System for the link to work. Registration is free!)
    • Read the API RP 1183 press release explaining the newly developed safety standard designed to help maintain the structural integrity of pipelines by addressing mechanical issues using new research from the Pipeline Research Council International (PRCI) and industry experts.
• Integrity Management (Pipeline Integrity Management) is a systematic approach to operate and manage pipelines in a safe manner that complies with PHMSA regulations.
• 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.
• PHMSA (Pipeline and Hazardous Materials Safety Administration) is responsible for providing pipeline safety oversight through regulatory rulemaking, NTSB recommendations, and other important functions to protect people and the environment through the safe transportation of energy and other hazardous materials.
• PRCI (Pipeline Research Council International) is the preeminent global collaborative research development organization of, by, and for the energy pipeline industry. PRCI is a community of the world’s leading pipeline companies, vendors, service providers, equipment manufacturers, and other organizations supporting the industry.
  • Listen to recent Pipeliners Podcast episodes with Cliff Johnson, president of PRCI.
• INGAA (Interstate Natural Gas Association of America) is a trade organization that advocates regulatory and legislative positions of importance to the natural gas pipeline industry in North America.
• 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.
• Cyclic loading is defined as the continuous and repeated application of a load (fluctuating stresses, strains, forces, tensions, etc.) on material or on a structural component that causes degradation of the material and ultimately leads to fatigue. Cyclic loading causes materials to deteriorate due to fatigue, often at lower loads and after a shorter time than normally expected.
• Cyclic pressure occurs when the pressure in a pipeline varies due to changes in operating conditions or demand placed on the pipeline. Surges can also occur during common field operations activity.
• Ductility is usually defined as the extent to which a material can be deformed plastically and measured in uniaxial tension.
• D/t ratio (diameter (D) / thickness (t) ratio) is a formula used to prevent excessive stresses and strain on pipelines.
• O&M (Operations & Maintenance) is a comprehensive approach to performing pipeline tasks related to the operation and maintenance of gas and liquid pipeline systems. A robust O&M program provides personnel with the knowledge and understanding of each situation to enable them to correctly assess the situation and take corrective action.

API RP 1183: Full Episode Transcript

Russel Treat:  Welcome to the Pipeliners Podcast, episode 225, sponsored by EnerACT Energy Services, supporting pipeline operators to achieve natural compliance through plans, procedures, and tools implemented to automatically create and retain records as work is performed. Find out more at EnerACTEnergyServices.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. To show that appreciation, we give away a customized YETI tumbler to one listener every episode. This week, our winner is Shelli Myers with Whitewater Midstream. Congrats, Shelli. Your YETI is on its way. To learn how you can win this signature prize, stick around till the end of the episode.

This week, Aaron Dinovitzer joins us to talk about API 1183 for the assessment and management of pipeline dents. Aaron, welcome to the Pipeliners Podcast.

Aaron Dinovitzer:  Thanks, Russel. It’s a pleasure to be here.

Russel:  Before we get into the meat of the conversation, what I’d like to ask is that you tell us a little bit about yourself, your background, what you do, and how you got into pipelining.

Aaron:  It’s a straightforward story. I was a structural and welding engineer working with an engineering consulting company. We’ve been doing that for the past 30 years.

We find ourselves doing a mix of research and service work, surrounded by a great team. We find that one of the areas that needed some development was the mechanical damage side. We started looking into dents and how they behave, and the rest is history.

Russel:  That’s perfect, because I’ve asked you to come on and talk about API 1183. That’s just the background you need to talk about that subject. First off, tell us a little bit, what is API 1183, and where does it come from?

Aaron:  If we go back to 2015, there was pipeline failure. As a result, the National Transportation Safety Board, NTSB, issued some recommendations both to API and PHMSA or the U.S. Department of Transportation related to dent assessment and repair criteria. At that time, there had been a fair amount of research work done by the Pipeline Research Committee International [PRCI], INGAA, and others.

There was a realization within PRCI and API that there was enough information to develop a recommended practice for mechanical damage. This would embrace or take up all of the research and the understanding that was developed to assess and mitigate the effects of dents in pipelines.

Russel:  I have to say I’m not an Integrity Management guy. This is outside my expertise. Is it safe to say that prior to this standard being formalized there was a lot of information out there for people to analyze and evaluate dents, but there really wasn’t any common industry practice?

Aaron:  There was regulation, and there were industry practices, but they were varied. What we know from the research is that we’ve learned things that challenge the standards. The regulations and standards, for instance, characterized dents based on their depth.

What the research showed was that we had to take account of the shape of the dent, not just how deep it is, but what its curvature is like and so on. We need to look at the three-dimensional shape of the dent. This we can get from our in-line inspection, our data. We have tools that were developed that will take into account this to understand the potential for crack formation during indentation, the potential for a failure during over-pressurization or pressure failure, or understand fatigue as a damage accumulation due to cyclic loading during operation.

Russel:  That raises a question. I know that historically dents have been looked at by how deep they are. That’s been the primary evaluation criteria.

I want to ask these questions. Would it be correct to say that it’s possible to have a fairly large dent with fairly small mechanical damage? Likewise, it’s possible to have a fairly small dent with fairly high mechanical damage? Is that a correct statement?

Aaron:  Yeah. I’m going to unpack a little bit of what you’re saying there. Dent is, we recognize that as a deformation of the pipe wall to a third party or an outside force on the pipe wall, so causes the pipe wall to deform.

Where you’re going with mechanical damage is you’re talking about, say, for instance, a strike by a third party, a backhoe tooth that’s causing a gouge, so removal of the material.

In the regulations, the way they’re set out in some of the standards, we would look at the dent by its depth. Then we’d say, “Over a certain depth, it’s not acceptable.”

What we would also say is if there’s a stress riser, which could be, as you’re talking about, a gouge, but it could also be corrosion or interaction with a weld. Under all of those, we identify the dent with a coincident feature as being unacceptable. We look for the dent to be remediated in short order.

What these new tools that we’ve developed allow us to do is do an engineering critical assessment or fitness for purpose type of assessment that allows us to say, “How severe is this dent with the coincident feature,” and understand the life or how quickly we need to react.

Russel:  Everything’s easy till you know enough about it. Very quickly, as you have this conversation, you start getting into some really interesting questions about dents. You’re talking about gouges.

What I know, and again, it’s limited, there’s two primary kinds of mechanical damage I’m familiar with at least, some digging damage, like a backhoe. The other would be pipelines that are in areas where there’s lots of rock, and those rocks are impinging up against pipelines. That can certainly happen over time.

Then, what kind of rocks are they? Are they rocks with sharp edges? Are they rocks with round edges? That’s why I’m asking the question, because to me, a fairly large indentation, but a ductile roll is very different than “I hit it and I created a very small, not very deep, but very sharp-edged dent.”

Aaron:  Where you’re getting at is exactly where we started. You can have different dent features with different shapes. They can be of the same depth, but have significantly different outcomes in terms of, “Will a crack have formed during indentation, or how will the pipe wall respond to internal pressure in terms of cycling?” Then we can have fatigue damage accumulate.

What we also know with these dent features is they’re not a static shape. As the dent is formed, we deform the pipe wall. As soon as we remove the indenter, the pipe wall is free to move and there’s a fair amount of elastic spring back. The formed dent versus the dent that’s in service can be significantly different for a restrained or an unrestrained dent.

That brings us to the two different, let’s say, extreme cases, scenarios, or types of dents. A restrained dent remains in contact with the indenter, such as a pipeline sitting on a rock, versus an unrestrained dent where there may have been some load applied to the pipe wall, but somehow that indenter moves and it’s unrestrained.

The third-party damage, the contact with the backhoe would be one example of that. You can also have rocks. The pipe is lowered onto a rock and then eventually, the rock moves through the soil and leaves the pipeline unrestrained.

Russel:  It’s like people don’t think about rocks moving. They might not in the context of just sitting there watching it, but rocks move.

Aaron:  Yes, they do.

Russel:  That sets a great context. It goes to the complexity of evaluating dents, and how they’re unique to some of the other things you evaluate. What’s 1183 attempting to accomplish?

Aaron:  If we start at the very beginning, 1183, what it tries to do is provide some standardized terminology. That was a gap to start with. How we call things, for instance, as we talked about, applying the right term to a gouge. It provides essentially a toolbox.

There’s a variety of different technical tools that are available to understand different modes of failure, and provide the ability to treat dent features. What we’re able to do or what we have rules for are three different failure modes, as I mentioned.

The risk of indentation cracking. As we’re forming, then we could form a crack. Understanding the failure pressure of the dent feature, as well as understanding the response to cyclic pressure or fatigue. The way that the assessment standard is set up, or the recommended practice is set up, there’s a series of different elements included.

The first is set up in a bit of a flow process. In the first process, essentially, we collect our data. We describe what data needs to be collected. Then what we do is we define which features are, in fact, dents versus not dents. The flow process that we go through starts with collecting up our information. This can come from inline inspection.

The next thing, once we have this data that describes the geometries of all these different features, what we decide is we put these features in the different bins. These are features that we believe are dents and these are features that are not. For instance, wrinkles and buckles are formed differently, and potentially have different behaviors. We set them aside for different assessment procedures.

For those features that are dents, then what we’ll do is we’ll look to see, are there any coincident features? For instance, is there a corrosion feature that was identified by, say, the inline inspection tool that coincides with the dent, or is there a well or is there a gouge?

We find the coincidence and define whether they are, in fact, interacting. If they’re interacting, they affect the life of the feature. Having done that, we move on to screening tools. There’s a series of screening tools that are relatively simple, quick, and easy to use. What they do is identify features that are non-injurious.

What they say is, “While you found this feature, it’s going to have a long, safe life and it’s not worth spending more time on. You can monitor it from the future, but it’s not likely to be an integrity threat at this time.”

Then, for those features that we can’t put into that bin of being non-injurious, then we go on to the assessment tools. They tend to be a little bit more involved.

What they’ll give you is they’ll give you a failure pressure. They’ll give you an assessment of the fatigue life and different things. Takes a little bit more effort, a little bit more data, but what you get is you get the safety of those features understood.

Having done that, we go on to the next step. We make decisions on which features need remediation. If we need remediation, there’s also a section that talks about what are the different options available in terms of repair, change in operation, and so on, things to allow us to move forward.

Russel:  That’s a great overview of the process. The thing that always amazes me when you start talking about what Integrity Management engineers do, and the processes they’re going through is just how complex it can become. It can get extremely complex.

One of the things that’s going on is, as we’re getting more data off of the tools and as we’re getting more types of data from the tools, we’re actually making the analysis more complex. We can be more effective without analysis, but it’s getting to be more complex.

It’s not uncommon that if I ran a tool inline 10 years ago and identified 100 features, that I’d run that same tool with its newer capabilities and find 1,000 features.

Aaron:  That is correct. The inline inspection tools are improving daily. That’s one of the reasons we bring forward these assessment tools, because we are now able to identify not only the dent feature, but we’re also able, with good confidence, to identify the coincident feature.

There’s a research program that just finished. It’s just finishing up with Pipeline Research Council International, PRCI, where there was a series of performance trials.

Seven different inspection tools will run through strings of pipeline that had dents with a variety of different coincident features, cracks, corrosion, gouges, some inside the dent, some outside the dent to demonstrate performance.

What we find is that the performance is very good. We’re able to identify and size the corrosion features with good accuracy. We’re able to identify all these different metal loss type features. That gives us license – or gives us confidence – to use the inspection or the assessment tools that we’ve developed. It gives us some more fuel to support the use of API Recommended Practice, 1183.

Russel:  The challenge is also shifting from being able to identify a particular feature to finding the features that matter.

Aaron:  If you can find features, and you can size them, then, as engineers, we have tools to do the assessment. There’s some small gaps, but that’s what this Recommended Practice was brought forward to do was to bring together all of those different tools and make them available.

Russel:  Interesting. Can you walk us through a little bit about the content? You probably have done that, because you’ve talked about the process of gathering the data and evaluating the features you’re finding, and then applying what tools go with what features for analysis and that sort of thing. Can you walk us through what the content of the standard is?

Aaron:  In a nutshell, if we want to characterize the standard in a very simplistic way, it’s a toolbox. What we have is we have two different sets of criteria. As I mentioned, these screening type criteria, which are relatively simple criteria that allow us to consider the characteristics of the pipe, the characteristic of the feature we’re looking at, and our operations.

For instance, I keep talking about fatigue as an issue. Fatigue is a response to cyclic pressure. That comes from the operations of the pipeline. Depending on how we operate our pipeline, we’ll get more or less cyclic pressures. The severity of the operation will be more or less.

If we can demonstrate a lesser severity of operation, then what we could also say is that fatigue may not be an issue. If you get no cyclic loading, then you won’t have fatigue generated, regardless of the dent. There are a variety of different criteria. Some of them are related to the pipe wall stiffness.

D/t is how we evaluate the diameter to wall thickness ratio. If we have a very low D/t ratio, the pipe wall is relatively stiff and it doesn’t respond to cyclic pressure. Again, it may rule us out. It may put us in one of these off-ramps, as some people call them, to say, “This feature becomes noninjurious because of the stiffness of the pipe wall.”

We may also demonstrate that while there is interaction with a coincident feature, a corrosion, for instance, the corrosion may not be significant enough or a high enough stress riser to cause the feature to be injurious.

What the standard allows us to do is essentially bring our engineering analysis tools to the front, and be able to use them to do assessment on the features that we find.

Russel:  Yeah, interesting. I want to talk a little bit about what’s in the PHMSA rules versus what’s in the standard. I’m getting out of my water here for sure, but if I recall correctly, PHMSA says, you’re required to look at dents six percent and greater.

I would think there’s a possibility that there’s dents smaller than that that might have safety impact. How does the standard address that, and how does that get reconciled with what’s in the rule?

Aaron:  In the PHMSA regulations, what we find is that they’re very prescriptive. They’re very clear in terms of, if you have a dent over a certain depth, or if there’s interaction with a stress riser, which could be your corrosion or your weld or your gouge, they become a more immediate repair.

One has to address the situation more quickly, rather than a plain dent. What they don’t recognize is that you may have, as you mentioned, a deeper dent, but it may be more benign than some shallower, but sharper dent.

For example, we’ve seen through consulting, and we do a lot of work with different pipeline operators, one can have a relatively deep dent that has a very long fatigue life. It’ll last. It’ll have 20s, 30s, 100s of years of life, versus a more shallow dent that is less than six percent deep, but it’s very sharp.

It may have quite a short fatigue life, if you want to call it, maybe in the 5s, 10s of years and so on. It’s simply not just the depth of the dent that we have to consider.

What tools allow us to do is consider both, the shape of the dent feature, but also the impact of the operational conditions as well as the effects of interaction with other features, such as your corrosions, and so on.

Russel:  What’s interesting to me about this conversation, Aaron, is if I try to think like an operator. Operators have a certain budget they have available to do their O&M. All of the Integrity Management falls under that O&M budget. They are constantly faced with the challenge of figuring out, “What do I put on the dig list? How fast do I put it there?”

If I’m required to put everything that’s six percent and over on the dig list, but I have some other, smaller things that might have a greater safety impact, that puts the operator in quite the conundrum.

Aaron:  It does. I think what’s going to happen, or what we see happening, is the operator will have the inspection done. They’ll run an inline inspection tool. They’ll receive back the inspection data. What they’ll do is they’ll run some screening tools.

Very simple application. What they’ll be able to do is separate the data into, say, three bins. One bin where these features are definitely not an issue, and they can set them aside. Then, there are other features that are definitely an issue. The screening tool rates them as severe.

Then, you’ll have a middle band of features that are on the bubble. What you can do is you can do further assessment of them, and define their lives. Then, rank them in terms of risk. There’s a finite budget for maintenance activities. What you want to do is make sure that if you’re spending a dollar you get a dollar’s value out of it.

Russel:  You want to spend that dollar in a way you get the most safety impact.

Aaron:  That’s right.

Russel:  You could actually quantify that if you look at, well, the safety risk of this feature is X and the dollar I have to spend to repair it is Y. I can actually put an algorithm behind that, and look at how to optimize it. We love algorithms, and we love to optimize. That’s one of the things as pipeliners, right?

Aaron:  These are tools. You know what? We’ve had instances where there’s some uncertainty, but what the tools also allow you to do is explore that uncertainty. You can say, “What if this scenario exists? What if that scenario exists?”

Then you can say, “Under what conditions is there a hazard to the integrity of the pipeline?” You will, obviously, do some digs to verify the inline inspection. You’ll do some digs for your maintenance programs.

The idea here is what you can do is you can get a better feeling before you program your digs. Define where you’re going, and what you’re doing based on the assessment tools.

Russel:  That’s interesting. I want to ask your opinion. So, if you want to not answer the question, I’m cool with that. What’s your thoughts about how 1183 might cause PHMSA to reconsider how some of its rules are written?

Aaron:  All along through the development, PHMSA, the regulator, as well as a large number of folks from the community, the pipeline industry, were involved in development. So, they’ve seen it coming. They’ve understood what’s going on. Have offered special permits. People can apply to apply engineering critical reassessment or fitness for purpose for dents.

The industry hope is that, at some point, the standard itself will be adopted by reference into the code of federal regulations, the regulations for pipelines.

I believe what’s going to happen here is – it’s a process. PHMSA has to find itself becoming more familiar, more comfortable with the regulation, and demonstrate itself through use in some of these special applications. Then, eventually, it’ll get adopted. It’s a process. We’re going to get there eventually, but we’re not there yet.

Russel:  The government moves slow and methodically. Often, that’s a good thing. [laughs]

Certainly, PHMSA has been pushing and promoting the idea of moving to more risk and performance-based approaches versus prescriptive approaches that allow the operators more flexibility in their decision-making. Personally, I think that’s a good thing. I think that’s the direction we need to go, but moving in that direction needs to be done carefully would be my take.

Aaron:  The tools, the processes, there in API Recommended Practice 1183 are exactly that. It’s a toolkit. Fundamentally, the operator’s role is to identify those tools that best suit their program, consider the system, their operation, the characteristics of their pipeline, their inspection program, the number of features, the types of features, their risk tolerance.

They take all of this into account. What they’re able to do is set up their Integrity Management program based on the tools that are available in API Recommended Practice 1183.

Russel:  That’s awesome. When was 1183 originally published?

Aaron:  1183 was published in 2020. Since then, there continues to be ongoing research. There are discussions going on that perhaps there’s an opportunity to enhance or improve what’s available at the moment.

Russel:  2020 is relatively recent. Particularly in terms of the way that regulatory and standards evolve, that’s relatively recent. The fact that they’re already looking at a new version or a revision tells me that there’s a lot of learning going on as they try to implement the standard.

Aaron:  I think there’s two different elements that are going on. There was a thirst for having this type of resource available. People are applying it – the inline inspection tools. Companies are able to report in a fashion consistent with the standard. The operating companies are making use of it.

What we find is when you make use of a tool, you identify where it works and where it doesn’t. You’re identifying gaps or opportunities for improvement. You’re also finding opportunities for increased clarity. It could have been better to say it this way rather than that way.

Some of the gaps were known. They were being addressed by organizations like PRCI. PHMSA is continuously sponsoring research as well. There has been significant research that was completed in the last three to five years that was not available when the standard was being assembled.

Russel:  That’s always the case. Particularly highly technical standards, by the time they’re published and out, they’re already six months to a year old at least, because the technology continues to evolve. We’re always looking for newer, better ways to think about stuff.

Before we wrap here, Aaron, let me ask you this question. What do you think that all pipeliners ought to know about 1183? If you were going to say, “Even if you’re not an integrity management professional, here’s what you ought to take away from this conversation.”

Aaron:  I think that on the whole, it is a portion of the Integrity Management programs that all pipelines will maintain. It does provide us tools at different levels of complexity that can be applied. It allows us to assess mechanical damage or dent features. What it does is it gives us the ability to manage these features rather than simply react to very specific timelines on remediation.

Russel:  Awesome. I think that’s great.

Being a guy who’s worked on some standards committees, and has read a lot of these standards, this kind of conversation, for me, is extremely helpful because I actually think I could sit down and read 1183 and maybe even understand it.

Some of these standards, if you just drop yourself into them raw without any context, it’s very hard to understand what they’re trying to say.

Aaron:  When we wrote up 1183, we tried to include a fair amount of background description, as well. There’s more than its fair share of references to the background reading, if we want to go further than the standard.

What it allows you to do is both make use of the tools, but also, hopefully, have an understanding of how mechanical damage behaves, how the tools were developed, and where they came from.

Russel:  That’s good. I guess in my copious free time I could break open a copy and read it for some good fun by the fireside.

Aaron:  Your definition of fun and mine may be different, but it is interesting reading, nonetheless.

Russel:  Just for the record, that’s highly unlikely to happen. Listen, this has been great. I found it very educational, very informative. I really appreciate it.

If anybody wants to know more about this standard, and how to apply it, how would they get in touch with you?

Aaron:  The standard itself is available from the American Petroleum Institute, API. If they want to get in touch with me, certainly email works. I am always happy to hear from people, and do my best to answer questions.

I suppose you’re going to provide my email contacts?

Russel:  Yeah. Thanks for asking the question, Aaron. We always put up a show notes page for every episode so there’ll be links to resources. There’ll be a full transcript of the episode. We’ll put a page up for yourself on the website so people can look you up and find your contact information.

We try to put this all together in a way that it’s a resource to the industry so they can listen to it. If they want to learn more, go to the website, and dig a little deeper. We’ll definitely put all your contact information up there, and link it all up.

Aaron:  Fair enough.

Russel:  Listen. This has been great. I appreciate it. When they come out with 1183 with revision, I might just ask you to come back, and tell me more.

Aaron:  Thanks, Russel. It’s been a pleasure.

Russel:  I hope you enjoyed this week’s episode of the Pipeliner’s Podcast, and our conversation with Aaron. Just a reminder before you go, you should register to win our customized Pipeliner’s Podcast YETI tumbler.

Simply visit pipelinepodcastnetwork.com/win and enter yourself in the drawing.

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

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