In this month’s edition of the Pipeline Technology Podcast sponsored by Pipeline & Gas Journal, Inessa Yablonskikh of Baker Hughes discusses her recent P&GJ article, “When Pipelines Strain Assessment Exceeds Capacity,” with host Russel Treat.

In this episode of the podcast, you will learn about the different types of pipeline strain loads, how the construction of pipe is critical to understand the effects of corrosion and defects, the need for tools to pull information together to understand risks, and more topics critical to supporting pipeline integrity management.

Pipeline Strain Assessment: Show Notes, Links, and Insider Terms

• Inessa Yablonskikh is a Principal Integrity Consultant with Process & Pipeline Systems and Baker Hughes. Connect with Inessa on LinkedIn.
  • Read Inessa’s article in Pipeline & Gas Journal, “When Pipelines Strain Assessment Exceeds Capacity.”
  • Baker Hughes is an energy technology company that provides solutions for energy and industrial customers worldwide. Find out more at BakerHughes.com.
• Integrity Management (Pipeline Integrity Management) is a systematic approach to operate and manage pipelines in a safe manner that complies with PHMSA regulations.
• Strain-based Integrity Assessment is the process of assessing a pipeline in terms of the strain acting in the longitudinal direction of the pipe.
  • Stress-based Assessment is a more common type of assessment that considers the pipe’s stress in the hoop direction. The hoop stresses come from the internal pressure.
• Inline Inspection (ILI) is a method to assess the integrity and condition of a pipe by determining the existence of metal loss, cracks, deformities, or other structural issues that could cause a leak or rupture.
• DOT (Department of Transportation) is a cabinet-level agency of the federal government responsible for helping maintain and develop the nation’s transportation systems and infrastructure.
  • 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.
• Girth Welds join two pipes along the circumference to enhance the viability of the pipes when placed into the field. Girth welds are helpful reference points to detect the location of an anomaly in the pipe.
  • PHMSA issued a safety notice on line pipe strength in 2009, “Pipeline Safety: Potential Low and Variable Yield and Tensile Strength and Chemical Composition Properties in High Strength Line Pipe.” It notified pipeline system owners and operators of the potential for high grade line pipe to exhibit inconsistent chemical  and mechanical properties.
    • Another safety notice was issued on girth welds in 2010, “Pipeline Safety: Girth Weld Quality Issues Due to Improper Transitioning, Misalignment, and Welding Practices of Large Diameter Line Pipe.” The advisory bulletin was issued to notify owners and operators of recently-constructed large diameter natural gas pipeline and hazardous liquid pipeline systems of the potential for girth weld failures due to welding quality issues.
• The National Energy Board of Canada published a notice, “Standards for Manufactured Pipe & Fittings and the Potential for Substandard Material Properties,” that examines current quality assurance requirements and processes and procedures used to validate pipe and components on pipeline systems and identifies any gaps or shortcomings in the quality assurance specifications that allow pipe or fittings to be manufactured that do not meet the intended material quality requirements.
  • API 1104 (Standard for Welding Pipelines and Related Facilities) presents methods for the production of high-quality welds through the use of qualified welders using approved welding procedures, materials, and equipment.
• YS means the material yield strength for steel pipe or weld.
• TS means the material tensile strength for steel pipe or weld.
• Pipeline Strain Assessment Tools include IMU and AXISS™ from Baker Hughes.
  • IMU (Inertial Measurement Unit) measures the pipe curvature using a combination of accelerometers and gyroscopes.
  • AXISS™ from Baker Hughes is an axial strain measurement technology tool that provides clear insight into the impact of the axially-orientated environmental forces influencing pipelines.
• NDT (non-destructive testing) is a group of noninvasive analysis techniques to determine the integrity of a material component or structure, without the need to take apart or destroy the test object. NDT includes several different types of tests and techniques to perform the assessment.
  • Magnetic inline inspection uses Magnetic Flux Leakage tools for detecting metal loss anomalies in a pipeline.
  • Crack detection in-line inspection includes ultrasound and electro-magnetic acoustic transducer methods to identify various types of cracks in a pipeline.

Pipeline Strain Assessment: Full Episode Transcript

Russel Treat:  Welcome to the Pipeline Technology Podcast, episode 6. On this episode, our guest is Inessa Yablonskikh, a Principal Integrity Consultant at Baker Hughes. We’re going to talk to Inessa about her September 2020 article in Pipeline & Gas Journal entitled, When Pipelines Strain Assessment Exceeds Capacity.

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Announcer:  The Pipeline Technology Podcast brought to you by Pipeline & Gas Journal, the decision-making resource for pipeline and midstream professionals. Now your host, Russel Treat.

Russel:  Inessa, welcome to the Pipeline Technology Podcast.

Inessa Yablonskikh:  Thank you very much, Russel. Thank you for inviting me.

Russel:  It’s great to have you. I’ve asked you to come on and talk about your article in the September issue of Pipeline & Gas Journal related to strain assessment. Before we dive in, maybe you could tell me a little bit about yourself, how you got into this business.

Inessa:  My name is Inessa Yablonskikh. Currently, I work as a principal pipeline integrity consultant for Process and Pipeline Services, Baker Hughes. I work in the product development team.

My areas of interest are pipeline strain and stress, and strain-based integrity assessments, pipeline risk assessments, and pipeline integrity management systems. By education, I’m a mechanical engineer, and I think my work is fun.

Russel:  [laughs] You’re perfect because you’re my kind of engineer. I like engineers that like doing technical stuff. I think in pipelining, strain and stress assessment is about as technical as it gets. What is strain-based integrity assessment, and why is it important?

Inessa:  Strain based integrity assessment, in our paper, speaks about assessing pipeline in terms of the loads acting in the longitudinal direction of the pipe as opposed to a more common stress-based assessment, which is considering the pipe’s stresses in the hoop direction. The hoop stresses come from the internal pressure.

Russel:  Just trying to put this in simplistic terms, strain is basically pulling on either end of the pipeline like trying to pull the pipeline apart versus stress is inside the pipeline pushing out, basically trying to blow it up like a balloon?

Inessa:  It is true. Don’t forget, the longitudinal strain also bends the pipe. When we are talking about strain-based integrity assessment, we are doing our best to consider both of the components. It’s the bending part and the axial part.

As you know, the hoop stress which is coming from the internal pressure is very high. It is commonly considered in most of the “fitness for purpose” assessments. Have you ever tried to boil yourself a Frankfurter sausage and overcooked it?

Russel:  I don’t boil my Frankfurters. I grill them, but yes I have. [laughs]

Inessa:  Have they ever split?

Russel:  Of course, yes.

Inessa:  How do they split? Do they ever split across or along?

Russel:  They generally split along the length of the sausage.

Inessa:  This is it. This is because the hoop stress is much higher than the longitudinal stress, in general terms, when your sausage or your pipeline is not additionally loaded.

Russel:  I’m never going to be able to grill a hotdog or a bratwurst the same way ever again, Inessa. That’s a great visualization. I love that. That’s really helpful. What would cause a pipeline to be under strain?

Inessa:  In terms of the common methods of assessing fitness for purpose for a pipeline, the hoop stresses coming from the internal pressure were always considered more important because they are higher unless the pipeline is under additional loading.

This additional loading can come from various sources. It can be geotechnical loading, or it can be unintentional construction loading. When you speak about the geotechnical, it will mean all these pipelines which are in mountainous areas, which can be built in the areas of possible landslides, or they are subject to washout and flooding.

They can be built on top of old mines and can be subject to the soil subsidence or settlement. They can be subjected to earthquakes as well. Another source of the longitudinal strain is the natural fluctuation in the pipeline temperature and pressure [causing expansion and contraction].

Russel:  Just the stress is associated with the metal changing its length as the temperature changes?

Inessa:  Yeah.

Russel:  Interesting. I want to try and summarize that as slow. Primary things would be gradients, I would think. If I’ve got a long length of pipe going up or down a steep gradient, that’s going to create longitudinal strain.

Anything that causes the pipe to move is going to create longitudinal strain, so any soil movement, subsidence of, I guess, a water crossing if transitioning from where the pipe is underground to where the pipe’s in the water but not underground, that type of thing. All of that is going to cause strain loads.

Inessa:  Any geographical activity. You’re right. Any land sliding, or any subsidence, or anything which means that the ground is not stable and it acts on the pipeline making it move either sideways or in the direction of the axies of the pipe.

Russel:  Basically movement that’s causing the pipe to try and get longer is a way to say that?

Inessa:  Not necessarily longer. It can be a pure bending if the load is just acting sideways. Some sort of an uphill of the soil which can be the frozen permafrost or something like that.

Russel:  I think we’ve answered the question, but why is strain integrity assessment needed versus the more common stress assessments?

Inessa:  My way of understanding is that, by now, the pipeline industry got a very good understanding of the stress-based integrity of the pipelines. There are lots of inline inspection tools and methods to account for any possible failures of the pipe caused by corrosion or by cracks.

I’m not saying that this problem or failures in longitudinal direction is completely solved, but it is well under control. Though the weather and natural force pipeline incidents constitute around a quarter of pipeline failures vs. those caused by corrosion.

However, I think that just the time came so that the pipeline industry now realized the importance of preventing the failures caused by longitudinal strains as well. Now we got ready to invest into prevention of such incidents.

Russel:  Certainly in the U.S. and in particular in Appalachia in the Marcellus and Utica Shale in the U.S. where they have a lot of hills or mountains, I guess. My part in Texas, you call them mountains. In Colorado, you call them hills but 3,500 foot fairly steep peaks that you are going up and down.

There’s been a number of landslides, particularly after heavy rains and things of that nature, that have been caused by some pipeline incidents. When those happen, they are more difficult to address because of where they are located.

Inessa:  That’s for sure. Geohazards have caused many catastrophic ruptures. This is an increasing area of concern for pipeline operators. That’s why it became an area of focus now for the pipeline operators to be able to measure such strains, assess them in the terms of their criticality, and prevent any adverse effects.

Russel:  One of the other things we talked about too, Inessa, when we were getting prepared for this conversation because you had to educate me in order for me to have this conversation [laughs] with you.

One of the things we talked about is the DOT requirements and how stronger pipe is actually contributing to some of the issues around strain. Can you talk to that a little bit?

Inessa:  Yes. That’s a very interesting issue. When we think about what particular pipelines are mostly susceptible to failures caused by longitudinal strain. We think about maybe three eras of pipeline construction and production. One class of era of pipelines, which are definitely susceptible to failures caused by geohazard and additional strains are vintage pipelines.

Because the pipeline is built before the 1970s, they didn’t go through the 100 percent testing of all the girth welds. The girth welds might contain some quite big defects in them. The welds’ quality itself was not as good as now. The vintage pipelines built before the 1970s are susceptible to such failures.

Then, there was a period of reasonably safe and good pipelines with girth welds, but some interesting issues happened. There were recently two safety notices issued by Pipeline and Hazardous Materials Safety Administration. One in particular, which was issued in 2009, was targeted on potentially unsafe pipe’s body manufactured by some plants and factories.

The problem was, at that time, the substandard line pipe was causing failures of pipe body. This was attributed to inconsistencies in the pipe production and reliability of yield and tensile strength and the chemical composition. The advisory was requesting the manufacturers to produce a better pipe.

A similar safety notice was issued also by the Energy Board of Canada in 2016. A result of the safety notices, manufacturers started achieving or targeting the best possible pipe characteristics to account for reliability in their testing practices of the tensile properties and for the methods of testing.

In the end, what happened is it caused the pipe to be supplied on the top boundary of the acceptable range for the yield stress and tensile stress. The pipe body was produced to be very good, very strong.

However, as you can think, the welding consumables were still chosen to match the steel grade, which expected to have the YS and TS around the minimal level of acceptable properties. It means that weld consumables, which earlier were able to achieve an even matched weld, now, they can only create an undermatched weld. This is especially important for manual welds. I know what you’re going to ask me. What does this even matched or undermatched thing mean?

Russel:  I was going to talk to that a little bit myself. When we had this conversation before, Inessa, it was eye-opening to me. To summarize what you’ve said so far is these two advisory notices came out.

The pipe manufacturers responded by making significantly stronger pipe. Then, we started having issues around the welds because the pipe in terms of its strength got ahead of what we can do with girth welds.

Inessa:  That’s correct.

Russel:  Go ahead, talk about undermatched and what that means.

Inessa:  This word of mismatch, which can be undermatched or overmatched, means the level of the ratio of the weld tensile stress to the pipe body tensile stress in the longitudinal direction.

When we speak about an undermatched weld, it means that the weld is weaker than the pipe. In this case, most of the longitudinal strain existing in the pipe will concentrate in this weld. The weld then is more likely to fail under longitudinal load.

Russel:  How does strain concentrate in the weld? How does that work?

Inessa:  The undermatched weld results in softening of the weld.

Russel:  Said another way, the load goes to the weakest point?

Inessa:  Exactly. So far, some pipelines have failed because of this phenomena of undermatching welds in high-grade pipelines but having lower strength of the weld in comparison with the pipe.

We are aware of at least 15 pipeline failures recorded in the last six years, which happened with the new pipelines in the first two or three years of the pipeline operation or even during the hydrotest.

Russel:  I’m sure you know this being somebody who takes new products and new solutions to market. You never know what you don’t know until you get it into production and then you learn.

Inessa:  That’s true.

Russel:  One of the challenges with any change or new technology is it takes a while to mature and stabilize. One of the things about some of these older practices that’s valuable is they’re extremely well understood, and you know when they do and when they do not work.

With the new stuff, you often don’t know that. You have a notion, but you don’t have the experience. You don’t have the history. That’s important in this kind of conversation.

Inessa:  Currently, this problem with undermatching welds in high-grade pipeline is understood by the industry. The industry players firstly are striving to have the API 1104 code for the girth welds updated to account for this new reality in terms of girth weld mismatch requirements.

Secondly, the industry is striving to create or choose technologies to achieve, at least, even matched welds for the high-strength pipeline. During the time when this research is going on, the way to prevent such failures is to account for this additional longitudinal strain and understand the true strain capacity of the pipe to prevent any problems.

Russel:  That’s a great segue, Inessa. How do you measure strain on a pipeline?

Inessa:  We need to measure two components of the strain. We need to measure the bending part and the purely axial strain. There’s two different technologies.

One technology is called the IMU, inertial measurement unit, which measures the pipe curvature. The tool contains sets of gyros and accelerometers. The data from them calculates the three-dimensional position of the pipe. With the help of the software, we can calculate the pipe curvature in the horizontal and vertical direction.

The curvature is directly connected and converted into the bending strain. This gives us the transverse loading, something which is moving the pipe out of its position sideways.

The IMU has been the conventional tool [for strain measurement] for many years in the industry. It is recognized for its ability to help in measuring the bending strains and also to map the pipeline, to know where the pipeline exactly is located, to see all the location parameters, whether it is in mountainous areas, and know the route exactly.

There has always been a recognized gap in knowledge of the longitudinal strain in the pipelines because IMU doesn’t allow you to measure the purely axial component of the strain. The purely axial component is something coming from the pipeline being extended like drawn from both ends or compressed. By measuring curvature, IMU cannot identify the purely axial component.

Secondly, Baker Hughes created a tool which is called AXISS™. Its purpose is measuring this pure axial strain component. The AXISS™ tool has an absolutely different principle. It is based on the electromagnetic effect of the change of the metal [material] lattice under the elastic strain. The metal [material] reacts to the elastic strain acting on it.

The sensors, which are mounted on the AXISS™ tool, react to the change of the magnetic characteristics of the metal. The good thing about it is that this is a direct measurement of strain. If there is strain, then it measures it. [laughs] If there is no strain, we don’t measure it.

Russel:  I guess one of the things that’s interesting to me about this measurement of strain versus stress measurement, generally with the tools we use for strain measurement, we get a direct representation of the strain. Where in these tools, there’s some calculation and analysis that has to happen.

With the IMU, I’ve got to get how much bending is occurring. Then, I’ve got to calculate the strain-based on the pipe and the amount of bending. I’ve got to know things about the pipe specifics. I’ve got to run math after I run the tool.

I would think that with the axial strain, because you’re looking at how the metal structure changes, you have to first have some understanding of what the metal structure is before it changes, before it’s under load. Again, you gather information, but there’s other calculations that have to occur.

Inessa:  Yes, exactly. It’s a lot of clever science in it. For the bending component, you look at how much out of straightness it is, what happens with the pipe, how much curvature is happening, and then you calculate it into [bending] strain.

For the AXISS™, you take a sample of the [pipe] material for calibration [purposes] in terms of understanding how much a particular pipe grade coming from a particular pipe producer creates the dependency of this electromagnetic response and the strain. You use it to calibrate your data, which comes from the tool. You can also do it based on the pipe material certificates, knowing what pipe grades are represented in your pipeline.

Russel:  I guess the interesting thing is you got to run the tool, but there’s a fair amount of analysis that has to occur after the tool’s been run to interpret what you actually have. Of course, that’s common across all kinds of tools. The analysis is always different. I would assume there’s a lot of math in this one.

Inessa:  Yes, certainly. There is an additional step in all this story. You need to combine the data streams coming from the IMU and from AXISS™ so that in the end, you come out with the total longitudinal strain, which now is comprised of both the bending and axial component.

You can confidently say that you know your strain condition of the pipe better because you accounted for the previously hidden axial part of it. Also, the fact that we can now measure the axial component helps a lot in other things.

Remember how I said that the AXISS™ [technology] reacts to the actual acting strain. It means that the fact that the alignment of the axial and bending data streams help us to prove that the bending strain also is real. It’s not coming from an intentional bending or other intentional construction process, but the pipeline is under strain. It helps us to prove it.

Russel:  What level of strain is acceptable, and how do you know?

Inessa:  After we have assessed the strain demand, which is this actual longitudinal strain acting on the pipe, we are now asking ourselves a question like, “What do we do now? Is it good? Do we need to do something about it?”

The way to answer this question is to compare the strain demand with the strain capacity, which is the actual measure of the pipeline segment’s ability to resist failure without any adverse consequences. The adverse consequences — in the case of tensile strain — it can be a rupture, especially in the locations of any anomalies of the pipe wall or girth weld anomalies or even a widespread area of corrosion. In the case of compressive strain acting [on the pipeline], it can be a buckle or other loss of the pipeline shape. We need to know under what particular strain can it happen. The rule of thumb is that the strain capacity can vary. For example, tensile strain capacity can vary from as low as 0.2 percent to more than 2 percent.

If you imagine an offshore pipeline, it goes through very high strains when it is being constructed and laid. But then, the strain capacity is very pipeline specific. As we mentioned, vintage pipelines can have strain capacity as low as 0.2 percent due to the presence of defects in the girth weld and other defects and anomalies associated with how they were built.

Also, the modern high-strength pipelines with undermatched manual welds or with softening of this heat affected zone area, they can also have a very low strain capacity. However, for modern pipelines with a good quality weld, we can expect [capabilities of] at least 0.4 percent of strain capacity.

Here is the question. We need to know, what is our pipeline? When and how was it built? What is the expected weld quality? Whether we are expecting any flaws, what can be their dimensions? Whether there was any misalignment of the girth welds when they were built, what were the welding requirements and what records of the non-destructive testing we have?

We can quote the testing requirements for the material and see, what is the expected tensile strength, fracture toughness. Which pipeline welds are manual, and which ones are automatic? Based on all of that, we will try to find the best models for the calculation of strain capacity and use all this information as much as we can.

Russel:  I’m trying to summarize to make sure I understand. Basically, I take all the details about how the pipeline was constructed and laid. I use that to calculate what strain capacity it has. Then, I go back and do a measurement. That tells me where I stand in relation to, “This is the strain I’m experiencing, and this is the strain capacity that I have?”

Inessa:  Correct.

Russel:  Sounds easy if you say it quickly. When you find that you have more strain than what is acceptable, what’s the mitigating activity? How do you address that?

Inessa:  If you find that the pipe is under more strain than it can carry without any loss of product or loss of operability, we need to think first of all, what can we do? The operator will have to make a decision, whether to mitigate [or arrest] the cause of the strain or maybe remove the strain from the pipeline, or repair some weakened locations, or just simply keep watching the pipeline.

There can be a few various mitigation actions recommended. If we find out that the calculated strain capacity is below the strain demand, we first of all review the evidence that the loading on this pipeline is active, that it actually is caused by any geotechnical or geological forces or loads. It might be that the loading is caused by construction and not going to grow in time [is inactive].

We will study the location of the pipe. We will review all possible information about the soils, about the ground the pipeline is running on, about the grade of the hills and mountains, about whether it is stable or not.

We will review all possible sources of aerial imagery or maybe any satellite imagery to monitor this area in time for any evidences of ground movement. There are also lots of field monitor techniques which help to prove, or otherwise, that the loading on the pipe is active.

Russel:  I guess the worst case would be if you found you had active load then you’d have to do something…

Inessa:  To stop it? Yes.

Russel:  To re-work the trench basically, to get the load off the pipe.

Inessa:  Concerning the measured strain, we can put some estimates on the strain capacity and to say whether the immediate integrity of the pipe is good or bad. What concerns the strain comparison, if, for example, from a set of consecutive inspections we find that the strain is growing, this can be an immediate cause of action.

There is no question about how much growing of the strain is good or bad. The tools can record a very, very low addition of the strains. For the bending strain, it is 0.04 percent where the IMU tool is sensitive to the growth in the bending. If growth is recorded, it means that we may need to do something.

The geotechnical processes, they are not linear. They can be growing slowly today, but then it can be an avalanche tomorrow.

Russel:  They’re very dynamic over time. The geotechnical part of this is just as complex. I did a podcast with a geotechnical engineer. We talked about this kind of things in detail, quite interesting. To summarize this, what would you say your advice to operators is related to strain and strain assessment?

Inessa:  If an operator has a pipeline in the area which is subject to ground movement threats, which can be hilly terrain, subsidence, landslide, settlement, or whatever, monitor your pipeline with the help of the IMU and AXISS™ tools.

If necessary, create a monitoring program of repeatedly measuring the strain over time to see whether it is growing and create the program of the strain-based integrity assessment for your pipeline.

Look after your pipeline essentially. Particularly, it is important for vintage pipelines with concerns in the girth weld quality and for modern pipelines, which are high-strength pipelines with the undermatching girth welds.

Your key to success is combining all the data streams you have. Combine all the information about the construction of your pipeline, about the non-destructive testing during the construction, then the data stream about the strains coming from the bending and axial loading.

If necessary, use all the information about the defects in your pipelines such as coming from magnetic or crack detection data for knowing where any anomalies are, like weak spots on the pipeline and dents are. Watch for evidence of corrosion, gouges, the girth weld problems coinciding with the areas of high strain on your pipeline because these all can influence your strain capacity of the pipeline.

By doing all these in combination, you will be able to, first of all, have the passport of your pipeline, know it’s the health in terms of the strain loading. Also, you will be able to prevent better any possible problems in terms of the failures caused by the longitudinal strains.

Russel:  Listen, Inessa, this has been great. This is a pretty steep learning curve for me, I will admit. I have tracked with what you’ve presented to us today. What I’m trying to do here is summarize my key takeaways. Then, I’d like just to get your opinion or your take on that.

My key takeaways would be this. Number one, all of the loads are additives, my stress loads, my strain loads, my different kinds of strain loads, the bending, and the axial. They’re all important. That’s a key takeaway.

The other thing is everything about the pipeline, in terms of how it was constructed, how the welds were done, what I know about corrosion and defects, all of those things likewise are important.

Finally, in order to have a picture, I’ve got to have a mechanism or a way to pull all that information together to understand what my real risk is. Did I get it?

Inessa:  I think you are right. The idea is to provide a single package of the solutions to support the operator who has problems with the geohazard loading of their pipeline. In this case, implementing the inspection program including both IMU and AXISS™ strain measurement allows for better understanding of the picture of the strain condition of this pipeline.

There are many advantages of combining multiple inspection technologies. I’m not speaking about strain assessment only. As you said, it is strain assessment, it is magnetic inspection for wall loss, correct measurement, so that when all these data streams are put together, you will have a better understanding of the present and future of your pipeline, and can plan the life of this pipeline better.

Russel:  That states it well. It’s getting a comprehensive picture and adding. This is another tool within the toolbox to manage pipeline integrity.

Inessa, thank you so much for coming on the Pipeline Technology Podcast. We really appreciate it. I would encourage the listeners to read the article in the September edition of Pipeline & Gas Journal.

Inessa:  Thank you very much. The pleasure was mine.

Russel:  I hope you enjoyed this week’s episode of the Pipeline Technology Podcast on our conversation with Inessa. If you would like to support this podcast, the best thing to do is to leave us a review on Apple Podcast, Google Play, or on your smart device podcast app. You could find instructions at pipelinepodcastnetwork.com.

If there is a Pipeline & Gas Journal article where you’d like to hear from the author, please let me know either on the Contact Us page of pipelinepodcastnetwork.com or reach out to me on LinkedIn. Thanks for listening. I’ll talk to you next month.

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Transcription by CastingWords