This week’s Pipeliners Podcast episode features Michael Stackhouse of Phillips 66 returning to the podcast to discuss the latest industry developments around data sharing to support Integrity Management.

In this episode, you will learn about industry collaboration that is currently happening with inline inspection and NDE, how data is being shared across pipeline operators, the real-world tests that are being run at the PRCI testing center, the opportunity for pipeline operators to learn from each other and share data in a collaborative environment, and more Integrity Management topics.

Integrity Management Collaboration: Show Notes, Links, and Insider Terms

• Michael Stackhouse is a leader of Asset Integrity for Phillips 66. Connect with Michael on LinkedIn.
  • Phillips 66 is a diversified energy manufacturing and logistics company with more than 140 years of experience supporting global energy needs.
• Integrity Management (Pipeline Integrity Management) is a systematic approach to operate and manage pipelines in a safe manner that complies with PHMSA regulations.
• API (American Petroleum Institute) is the only national trade association representing all facets of the oil and natural gas industry, which supports 10.3 million U.S. jobs and nearly 8 percent of the U.S. economy.
  • API 1176 is a recommended practice developed and published by API that provides pipeline operators with best practices in the integrity management of cracks and threats that give rise to cracking mechanisms.
• PRCI (Pipeline Research Council International) is a community of the world’s leading pipeline companies, vendors, service providers, equipment manufacturers, and other organizations supporting the oil and gas industry.
  • PRCI opened the Technology Development Center (TDC) in Houston for the advancement of pipeline research.
  • Cliff Johnson is the president of the Pipeline Research Council International (PRCI). Listen to recent Pipeliners Podcast episodes with Cliff Johnson on how the PRCI has developed a data hub to store information from across the pipeline industry.
• 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.
  • 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.
• NDE (Non-Destructive Evaluation) employs sensor and imaging technology to assess the condition of components, plant, and engineering structures of all kinds during manufacture and in-service.
  • Ultrasonic Testing (UT) is a type of non-destructive test (NDT) that uses ultrasonic waves in the test area.
• ASNT (American Non-Destructive Society) is a technical society for nondestructive testing (NDT) professionals. The organization provides a forum for the exchange of NDT technical information, educational materials and programs, and standards and services for the qualification and certification of NDT personnel.
  • SNT-TC-1A (Personnel Qualification and Certification in Nondestructive Testing) provides guidelines that can be used by companies to develop employer-based, in-house NDT certification programs. Included are recommended skill levels for all levels of NDT qualification, the recommended training and experience hours for Level I and Level II personnel, and the examination eligibility requirements for  Level III personnel.
• Geomorphic Solutions helps pipeline operators understand, mitigate, monitor and plan for flood-related risks at river crossings.
  • Dr. Jeff Barry is a water resource engineer/hydrologist, specializing in fluvial geomorphology and evaluating hydrodynamic and sediment transport processes within river systems, with a particular focus on the risks that flood-related forces represent to oil and gas pipelines.
• Bell hole is a hole dug into the ground near a pipeline to allow for inspection to be performed. This is a technique used to widen a trench over a planned distance to allow for enough room for workers to perform the inspection.
• 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.
• Corrosion is the deterioration of a steel pipeline that results from an electrochemical reaction with its immediate surroundings. 
• Cathodic Protection (CP) is a technique used to control the corrosion of a metal surface by making it the cathode of an electrochemical cell.
• Pressure cycling captures the fluctuations that occur during the course of operations, such as starting and stopping pumps and moving product with varying densities and viscosities.
• Sonar uses sound to measure distances, communicate with objects, or detect objects in a defined space.

Integrity Management Collaboration: Full Episode Transcript

Russel Treat:  Welcome to the Pipeliners Podcast, episode 199, sponsored by ROSEN, the global leader in cutting-edge solutions across all areas of the integrity process chain, providing operators the data they need to make the best Integrity Management decisions. Find out more about ROSEN at ROSEN-Group.com.

[background music]

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

Russel:  Thanks for listening to the Pipeliners Podcast. I appreciate you taking the time, and to show the appreciation, we give away a cool, customized YETI tumbler to one listener every episode. This week, our winner is Mark Materna with Magellan Midstream. Congratulations, Mark. To learn how you can win this signature prize, stick around until the end of the episode.

This week, Michael Stackhouse returns. Michael, who guys by Stack, is asset integrity manager at Phillips 66, and he’s coming on to talk about industry collaboration, data sharing, and integrity management. Michael, welcome back to the Pipeliners Podcast.

Michael Stackhouse:  Thank you, sir.

Russel:  Well, it’s good to have you back. You were recently on the podcast, have been back on, in episode 124. We talked a lot about API 1176, crack management, and all of that. Maybe a good place to start is just tell us what’s been going on since the last time we talked with 1176.

Michael:  Yeah, that’s a good place to start. The API team who put together and spearheaded the creation of 1176 is currently going through a revision. Periodically, we open up the recommended practices and standards, make sure that they’re relevant, and keep them relevant through revisions as they come up periodically throughout the years. Right now, 1176 is currently going through a revision. There’s a large API team with a number of operators who are going to take a look at that document and keep it current.

Russel:  When do you think the thing will start coming out for ballot review? How far away is that?

Michael:  It probably is six months to a year to be balloted.

Russel: Okay.

Michael:  It takes some time to go through, wow, about 176 pages of a document to make sure everything’s relevant.

Russel:  Yeah, I’ve participated on some of the API committees in other domains, and it always takes way longer than what you think it’s going to take.

Michael:  [laughs] Yeah.

Russel:  That’s just part of it.

Michael:  It sure is.

Russel:  I know that there’s been a fair amount of industry collaboration going on around just Integrity Management in general, and with some specific interest around cracks and crack tools. Maybe you could tell us a little bit about what you’ve been participating in related to operator meetings with the crack tool guys.

Michael:  A couple of years ago, the API group — it’s the R&D work group — got together and decided to meet with the ILI vendors and asked them, “How do we help the vendors get in front of the technology and have the operators help the vendors get the technology as best we can?”

One of the things we heard loud and clear was we need real-world samples. We heard that from each one of the ally vendors as it pertains to cracks in particular. We got back to our offices, we talked it through, and we said, “Okay, let’s make a real effort here to get real-world crack samples and send them to the PRCI TDC so we can set up a test loop.”

It took us a little bit, but the operators came through. We have an 800-foot test loop that is currently at the TDC, it can run in a liquid service, where we put water in it, because ultrasonic tools [UT] are the best tools to find cracks.

With ultrasonics, you need a liquid coupling. We built an 800-foot test loop with real-world crack samples, and in particular, hook cracks in the seams, in order to test ILI tools and help them get better.

Russel:  I’ve been out to the TDC, and I’ve seen the facilities they have out there. It’s really quite fascinating what they do, how they’ve got that loop set up, and how they with the pipe, “Here are the faults we’re looking for,” and have got that data from that pipe from a lot of different tools, including handheld stuff. It’s really fascinating what they can do in terms of building a dataset for test purposes.

Michael:  Yeah, that’s for sure. We have eight acres out there, and a large portion of it’s set up for pull testing. Another section of it is set up for these test loops. The operators donated pipe with cracks in it, and then we scrub those pipes with NDE.

Out in the warehouse, we put them up on pipe stands, and it was a near laboratory setting, where you could spend hours upon hours testing this pipe and making sure we have the best available information from an industry perspective on what’s in the pipe.

Russel:  Yeah, so how many vendors have run their tools through this test loop so far? What’s been the challenges with getting the vendors to run, look at the vendor data, and all that?

Michael:  Truthfully, the biggest challenge has been COVID. A couple of our vendors are not in Houston, but the PRCI TDC is here in Houston. To get the tools and the technicians, like from Canada to Houston, has actually been a bit of a challenge, especially with quarantine rules and things like that.

We have one vendor that’s been through the test loop, and what’s really interesting is that test loop is designed to run it several times around the loop, several different speeds. Then we can take it out, turn it around, and go the opposite direction. The vendors can get multiple looks at the cracks in two different directions.

Russel:  Well, that’s fascinating. I’m wondering what you find when you do that. How different does the crack look when you’re running at a different speed and different direction?

Michael:  We want to give them as many chances to be successful as they can, and we want to be able to learn as much as we can by these test loops. We have not gotten any results from that first vendor yet. Our second vendor is set up for September, so we’re excited about that. We have two other vendors behind them already scheduled.

Russel:  Mike, I’m not an ILI guy by a long stretch. I can spell out I-L-I. That’s about what I know about ILI, but I do know a fair amount of doing research projects and what’s required to get something through its paces and out to market.

I would think, as a vendor, that I’d want to run, I’d want to grab that data, and then I’d want to do a bunch of back-office analysis and evaluation of what I found. That’s probably going to drive me to make some changes in my tool, and then I’d probably want to run it again.

Michael:  No, you bring up a great point. We’ve always set this up as a minimum of two phases. One was to get a baseline. Then hopefully, in 2022, they are ready to make those adjustments to either their tool or their processes, programs, or algorithms, and then come back out in 2022 and re-run it again. No, you bring up a great point.

Russel:  That’s the nature of how you get something really tuned up and ready to go add value in the marketplace, is you’ve got this iterative process of, “Okay, I know what I’m looking for.” I’m sure they saw the cracks, but really seeing exactly what they need to see, and knowing what they’re seeing, that’s the tricky bit.

Michael:  No, you’re exactly right. It’s not just detection. It’s identification and characterization. We have to be able to see the crack. We have to be able to identify it as a crack. We have to be able to identify it as a hook crack and not a lack of fusion.

We have to be able to size it, length, depth, and width. It’s multiple-faceted, so I’m hoping they got plenty of looks at these cracks, and they can tell us what the optimum speeds they need to run at and directions they need to run at, and hopefully get a lot of really good information.

We have a goldmine of samples. When we were testing the samples out at the TDC with a third-party NDE, non-destructive testing, the technicians giggled when they went past some of the defects, because there are plenty of defects.

I asked them, “Why are you giggling?” He said, “This is a treasure trove of defects. You guys have found the best sample set that we’ve ever seen.” [laughs]

Russel:  Yeah, I’m not an ILI guy, but I am that kind of geek. I would be the same way. It’d be like, “Look at all the things we can see.” I think one of the things you guys have done with this collaborative effort here is you’ve created a situation where both the operators and the tool vendors can look at a very wide variety of defects in very short order. You just don’t get that opportunity in the field.

Michael:  No, and I don’t think this has ever really existed in this manner with the operators and the vendors working together. They asked us for samples, real-world crack samples, and the operators came through.

Russel:  Yeah. Well, that’s awesome. It’s interesting, too, because one of the things we’re really challenging within the business, in our industry, is how do we do a better job of sharing information? There’s a lot of concern when you start sharing information that might be punitive, litigious, or something like that — there might have risk with it.

What you guys have done is you’re pulling samples out of pipe that you found in your programs that you decided to pull and then saying, “Okay, let’s put this in a run and let people look at it.” I think it’s awesome. It’s awesome.

Michael:  Yeah, it has been a really good project so far, and I’m really glad to be a part of it.

Russel:  Yeah. I’ll bet it’s a lot of fun. Talking about sharing, what is the industry doing to get better about sharing, beyond just getting some segments of pipe? Are there other things that are going on from an industry collaboration standpoint that people ought to know about or might want to participate in?

Michael:  Yeah. I think as a whole, we’ve all looked at the elephant in the room on data. We all have a ton of data, and what the struggle is is how do we share my data with you and your data with me, being such a huge dataset? I’ve worked on this problem a little bit with PRCI, and I think, if you eat the elephant all at once, it’s very daunting. How do we break up the data in different segments?

I’ll give an example. I was looking at our river-crossing risk data, and looking at it from a stance, “Well, if I was to share this information, what would it look like, and what could I share?” What I found was there’s data within our data that is incredibly shareable, like the characteristics of the river. That’s not anything that I couldn’t share or shouldn’t be able to share.

Russel:  That’s also, in some ways, that’s public domain, right?

Michael:  It is, but each one of us does our own data evaluation, boots on the ground, at the river. There’s four variables that we look at. We look at the ability for the river to change, of course, because we know it’s going to change.

It is slow change, in most cases, but we know that the river channel with different flood events can get deeper, so that’s one variable. How deep can a river get under certain flood events? Then we also know that the banks can change, the sides of the rivers. What is the potential for the bank to erode under flood events? What’s the potential for the bank to fail on flood events? Then the last one is how much migration are you going to get from the river? How much is the river going to change directions?

You’ve got to remember, we built these pipelines 50, 60 years ago, in some cases, when the river may have been smaller or shallower.

Russel:  Or in a completely different place.

Michael:  Exactly. What we have to do is monitor the characteristics and the river’s behavior. We’ve all put together risk metrics, similar to what I have spelled out, and there’s four variables that I think we could share as an industry. I think we could all learn from it.

It’s independent of my pipeline. I didn’t tell you how deep my pipeline is. I didn’t tell you where my pipeline was. All we’ve done is talk about rivers, so why we wouldn’t we be able to share that?

We currently have a pilot program within PRCI. We’ve been working with a river expert. His name is Dr. Jeff Barry. He’s with Geomorphic Solutions. He basically is the leading industry expert on river risk characteristics.

Russel:  Interesting. This might be a little bit off in the weeds, but recently, I was on YouTube, and I just look for videos I find interesting. I saw a video that was a hydrology lab at a university. They were running experiments about how a river shape changes by varying the speed of the current, the direction of the river, what you put in the river, and how that changes the banks, and all that kind of stuff. I’m wondering if you have ever looked at capstone projects around this kind of stuff. Are you familiar with capstone projects?

Michael:  A little bit. We do some of those here at Phillips as well, but I don’t think we’ve looked at it from that standpoint. I think that’s a great idea. I know that Dr. Jeff Barry has actually done some testing at a university as well, where he was using acoustics to hear the movement of the rivers, which was interesting.

Russel:  Oh, wow.

Michael:  You’re right, the differences between sedimentary deposition and the characteristics of it moving is exactly what we’re looking for. Yeah, I think working with universities or other experts like that is a really good idea.

Russel:  I’m sure there’s some Ph.D. engineer in the civil engineering department at A&M that would love the opportunity to do that kind of project. I’m sure there’s some engineers that need capstone projects to get their diploma stamped and get out and make a living, right?

Michael:  Yeah, this would be a good.

Russel:  It’d be interesting to look at that.

Michael:  Definitely.

Russel:  I want to segue a little bit and talk about in-the-ditch NDE. It seems to me that there’s a lot of opportunity for improvement in that domain. That’s a little different than running the ILI tools. You’ve got technicians that are actually in the ditch with tools collecting data, and all of that. Again, it’s something I don’t know a lot about, but what is the industry doing in that domain from a collaboration standpoint?

Michael:  That’s another good question. I think the last time we talked, we were talking about inline inspection and cracks, and we mentioned NDE in the last episode. We basically took it as an industry in two phases. One, improve, ILI, but two, improve NDE. As we have dove into the NDE process and industry, we’ve learned quite a few things.

Again, the key is samples. We need good, real-world samples from a midstream perspective in order for NDE technicians to test and qualify. The NDE companies themselves typically deal with thick, flat plates. Well, on the pipeline side, we deal with thin, curved pipe. It’s typically not as thick as the plates. It’s a lot thinner. The ultrasonic technique reacts differently to the different defects in that curved, thin setting.

When you have a thick plate, it can be easy to find a defect. When you have curved pipe, it’s actually somewhat challenging. What we decided to do was put together a qualification validation, use an API. They currently have a program for the refining industry, so what we did was create one for the midstream industry.

We got samples to test NDE companies to have them come out here and validate their qualification on midstream pipe. The first thing we did was test wall thickness, so we’ve got that out there. Then the second one was long seam defects. It’s still pretty new, but what we need is more samples as an industry, and we need to be putting more technicians through this NDE qualification process. Again, back to the samples. It really takes samples to get that done, and the operators have to get those samples.

Russel:  Yeah, that’s right, because they’re the ones that have them. One of the things that comes up for me as I think about what you’re talking about, Mike, is NDE is typically done in a ditch. I do a dig, I expose a joint of pipe, and then I set the technicians loose, and they go about gathering their data on the pipe.

I would think that you’d almost need to — once you get the samples, like with the test loop is — how valuable is it to have those samples in a ditch and see how you get the data in the ditch, versus having it sitting in a rack and see how you get the data? How big a deal is that, really?

Michael:  That might be a challenge, but I like the way you think. We need to be in the mud, laying down, ants falling on you…

Russel:  I don’t know that you need to drop ants on people, but there is an aspect of doing this in a confined space, and doing it looking up on the bottom of a pipe, versus doing it looking down on a flat plate.

Michael:  No, you’re exactly right. What we’re trying to do is we’re trying to get those samples, get their training up to speed from their company’s perspective, and then have something available to them so they can actually validate that qualification.

You’re 100 percent right. The human factors piece of this is huge. I think we’re taking it in phases. I like your suggestion, but I think what we’re going to do is try to create the samples first, get them tested on it, see how many we can get validated, and then maybe utilize that TDC to create maybe a bell hole or two, and see if they can’t crawl down in it. I like your thinking, though.

Russel:  I think there’d be some real value to that. Now, you could do it in a way that was more laboratory than pure field, right? So that you keep it out of the weather and that kind of stuff. Even so, just being in a confined space and having to get around a 360-degree pipe, that’s different than a piece of pipe’s sitting on a rack, and I’m walking beside the pipe. It just is.

Michael:  Oh, it totally is. The human factors piece is going to be a challenge from a testing perspective. The other thing that we did that was interesting, too, is typically, operators only deal with the middleman from the NDE perspective.

Let me give you an example. If I have a pipe in a dig, and I need it to be tested, I call the service provider that has the equipment and the technicians to give me the information. What we decided to do is go to the manufacturers. We’ve recently met with the manufacturers of the equipment that our third-party NDE companies use. We’ve actually learned a lot from that as well. The equipment that is available, the techniques that are available, the programs that are available.

The other thing that we’ve learned is the manufacturers want samples, too. Two weeks ago, we invited Olympus out to the TDC to test their equipment on some of the pipe as well. They spent the entire day out there. We scanned the seams both directions using multiple techniques. One side of the equipment was using a flat wedge. The other side was using a curved wedge, so we could see if the wedges make a difference in picking up the seam cracks.

They recently, a week ago, we went back out on there on Thursday and spent the entire day out there again. What we’re trying to do is try to figure out with the equipment we have what are the best techniques, and what techniques don’t work? That way, we can get smarter as an industry, and then we can be sharing that with our third-party service providers in order to get the best data we can from the ditch.

Russel:  That’s a great segue, because it brings up the next question that’s in my mind, is to what degree are there good standardized industry practice for doing this kind of work, versus it’s up to the service provider to have their practice?

Michael:  I think there’s lots of standards out there. From ASNT, the SNT-TC-1A process is sound, but I think if you get into the minutiae, it’s all around what are you testing? It gets back to the midstream component. I think we just have to expand on the midstream component of NDE testing and qualification. Again, it’s curved samples and thinner samples, and we need to be getting the NDE providers training and certification up and running around that.

Russel:  That makes sense, and then the follow-up question is do they need to select their technique and equipment based on the threat they’re looking for?

Michael:  Great point. Yes, indeed. If they’re looking for a crack in the pipe body, it’s different techniques and different equipment than you would if you’re looking for cracks in the seam. So good question. Again, we need samples.

Russel:  Yeah, and so [laughs] that just opens up a whole Pandora’s box for me. I need to build this a little bit, so you understand where I’m coming from. Again, I’m a novice in this domain, but I do understand some of the larger operators and what their dig practice is.

I know that it’s somewhat common that, if I’m going to a dig to investigate a specific threat, that generally, what I’ll do is I’ll open a ditch up, and I’ll get probably that segment and the girth welds on either end of that segment. Then, when I go and I do the NDE gathering, I’ll gather NDE on the entirety of that segment. Then that goes into my database to help with other analysis and assessment. That’s the tee-up. The question would be, well, if I’ve got to use different kinds of equipment and different kinds of techniques to look for different kinds of threats, when I have an open ditch, how much gathering’s enough?

Michael:  That’s a great point. Typically, though, we know where the targeted defects are going to be, based on the inline inspection. You may evaluate the entire joint visually, but then use your techniques on the targeted defects. Hopefully, you know what those targeted defects are based on the ILI results.

Russel:  Yeah, that makes perfect sense. [laughs] That makes perfect sense, Michael, but the flipside of that is I’m an engineer, and we never get enough data. I want every technique and every machine. I want to run it all on — I know that’s not realistic, but there is a little bit of that in this conversation, right?

Michael:  There is.

Russel:  The cost is in opening up the ditch. The cost is not in gathering the data once I have the ditch open, really.

Michael:  Yep, good point.

Russel:  Anyway, that’s the whole “how much data is enough” question, and that question is unanswerable.

Michael:  It is, and we get that question a lot in the integrity field.

Russel:  It’s not just integrity, but yes, I’m with you. The way to wrap this up, I know there’s a lot of people that listen to this podcast and they’ll listen to something that’s very specific and technical, like what we’re talking about here. This isn’t the domain they operate in, but they want to know about it.

What would you have to say around coatings and age of pipe as it relates to the industry and how we’re collaborating around that?

Michael:  That’s a good question. I’ve been in the industry a while. The more I look at some of the older coatings, the more I wish we had those older coatings back. A hand-applied coal tar…

Russel:  That’s probably a controversial opinion right there. I don’t know enough about this space to know, but I’m going to make that as a guess.

Michael:  You’re probably right. Some of the old hand-applied coal tar is still intact. It’s still perfect, even if it was built in the ’50s. It’s not about the age of the pipe or the coating itself. It’s about the environment around it and the changes that have happened around it that are affecting the coatings. Some of the older coatings are fabulous. They put it on thick, it’s structurally sound, and it’s still intact with the pipe.

Russel:  It makes you wonder why we don’t still do that.

Michael:  I have wondered that myself. Over the decades, we’ve gotten different coatings and different ways to apply it. All that’s done is change the way we have to look for the changes in the coating and the changes in the environment and how it affects those different coatings. You got to remember, coating is the number one tool to stop corrosion. If you don’t have the environment touching your pipe, you’re probably not going to have corrosion.

Russel:  That’s right.

Michael:  There’s so many changes around the pipe that happen that you have to monitor.

Russel:  It’s interesting, too. One of the challenges in our business is that we have so many of these vertical technical domains that we have to have a lot of competency and capability that when we start talking about cross technical domains like cathodic protection versus coating versus ILI versus pressure cycling, those conversations get interesting sometimes. What helps me in one area hurts me in the other, often, right?

Michael:  [laughs] Yeah, you’re right.

Russel:  Listen, this has been great. You got anything you want to talk about that we haven’t already covered?

Michael:  I feel like I didn’t finish much on the data sharing. We do currently have a project with several operators working to share river crossing characteristics. We are working with PRCI, we’re working with Geomorphic Solutions to try to come up with a way to put together a dataset that is shareable.

We’ve got several operators agreeing to pilot a project right now, and we’re in the middle of that project as we speak. Hopefully, what’ll happen is we’ll be able to share a map or a database with those four different characteristics of rivers. That way, operators can take a look at their pipeline and their assets and see if their assets are going to be affected by the different characteristics.

The other thing, and how it came up was, if I’m evaluating boots on the ground information and measuring river characteristics on my pipeline right away, but then right next to me is another operator, we ought to be sharing that information. So, the other piece of that share is, should we be sharing our schedules? Should I talk to Operator B and let them know that I’m going to be out on a river evaluating a river? I have an expert on that river with side SONAR capabilities and vegetation density measurement techniques right next to their pipeline. Would they want to be a part of that?

So, how do we share the schedules, how do we share the expertise, and then how do we share the data further? We’re right in the middle of that. Again, it’s breaking up the data. Not sharing everything all at once, because it seems pretty daunting, but how can we share bits and pieces of it? We can do that by breaking these different datasets up. Let’s take a look at, not the data, but the learnings from the data. That’s the river risk.

Russel:  The information, the processed data. And, I think there’s a lot of value and a lot of opportunity, and water crossing information is certainly one area, but there’s others as well. When you start looking at things like potential landslides or other kinds of things where multiple operators would all benefit from the same data, and where we can get better data for everybody if we collaborate about how we get that data.

Michael:  I’m hoping this project is just the stepping stone for the others. Again, we’ve been looking at it wrong. We’ve been saying it’s data, but it’s not. It’s what you’ve learned from your data is so much more valuable. Me staring at your data, I may not come to the same conclusion, but if you share the information that you obtained from your data, that’s valuable.

Russel:  I absolutely agree with that. I can’t tell you how many conversations I’ve been in where we all agree on some general assessment of the raw data. The real value is in the conversation about the details that we disagree on, because we all end up learning something in the midst of that disagreement.

Michael:  Great point.

Russel:  That’s one of the things that our industry does well. We can get to an agreement at one level and discussion at another and have that improve the overall understanding and outcome.

Michael:  Yes, sir. Definitely.

Russel:  Listen, I’m so grateful if you coming back on the podcast. Always good to have you. I always feel like I’m on a very steep learning curve when I’ve got you here talking.

Michael:  I appreciate it so much. Thank you.

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

If you’d like to support the podcast, please leave us a review on Apple Podcast, Google Play, or on your smart device podcast app. You could find instructions at pipelinepodcastnetwork.com.

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

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