This week’s Pipeliners Podcast episode features first-time guest Corey Richards of ROSEN discussing advanced tools available for pipeline operators to manage the unpiggable.

In this episode, you will learn about how Inline Inspection capabilities have advanced to run inspection tools through unpiggable pipe, how to overcome ILI issues with older pipe and newer pipe that is unpiggable, things to consider around PHMSA regulations for unpiggable, and more information for pipeline operators to think about in regards to inspecting unpiggable pipe.

Managing Unpiggable Pipe: Show Notes, Links, and Insider Terms

• Corey Richards is Canadian Regional Manager for the Challenging Pipeline Diagnostics Division of ROSEN. Connect with Corey on LinkedIn.
  • ROSEN is the current episode sponsor of the Pipeliners Podcast. Learn more about ROSEN — the global leader in cutting-edge solutions across all areas of the integrity process chain.
  • Learn more about the ILI solutions offered by ROSEN and how the Challenging Pipeline Diagnostics Division is leading the way in Unpiggable Pipelines Solutions.
    • Download This ROSEN Whitepaper: “Challenging Pipeline Diagnostics Solutions.”
• Integrity Management (IM) (Pipeline Integrity Management) is a systematic approach to operate and manage pipelines in a safe manner that complies with PHMSA regulations.
• ILI (Inline Inspection) is a method to assess the integrity and condition of a pipe by determining the existence of cracks, deformities, or other structural issues that could cause a leak.
• Pigging refers to using devices known as “pigs” to perform maintenance operations. This tool associated with inline pipeline inspection has now become known as a Pipeline Inspection Gauge (PIG).
  • Non-piggable pipeline is a portion of pipe that cannot accommodate a pig device, making it more difficult to inspect for defects. A pipeline may be non-piggable because of extreme bends, its composition, or changes in diameter.
• Non-Conventional Free Swimming ILI tools can be utilized for pipe that flows and has launch/receive capabilities. The pig is not attached to an anchor and moves freely within the line among the product in the line.
  • Tethered tools are used for ILI on pipe that lacks flow or lacks launch/receive capabilities, typically on legacy pipe. The tool is tethered to a source and typically enters and exits the pipe at the same location. It can be battery-powered using copper wiring to charge the unit.
  • Untethered tools can be launched from a single entry point, and can be deployed in a pressurized or depressurized pipe. This tool typically uses batteries for power and antennas for communication.
• MFL (Magnetic Flux Leakage) is a magnetic method of nondestructive testing that is used to detect corrosion and pitting in pipelines.
• EMAT (Electromagnetic Acoustic Transducer) is an ultrasonic tool that uses sound waves to perform non-contact inline pipeline inspection.
• PHMSA (Pipeline and Hazardous Materials Safety Administration) ensures the safe transportation of energy and hazardous materials.
  • CFR 192 and 195 provide regulatory guidance on the pipeline transport of natural gas and hazardous liquids, respectively.
• MAOP (maximum allowable operating pressure) was included in a bulletin issued by PHSMA informing owners and operators of gas transmission pipelines that if the pipeline pressure exceeds MAOP plus the build-up allowed for operation of pressure-limiting or control devices, the owner or operator must report the exceedance to PHMSA on or before the fifth day following the date on which the exceedance occurs. If the pipeline is subject to the regulatory authority of one of PHMSA’s State Pipeline Safety Partners, the exceedance must also be reported to the applicable state agency.
  • MAOP Verification includes six approved methods for reconfirming MAOP, as outlined by PHMSA in the recent Mega Rule: pressure test, pressure reduction, engineering critical assessment, pipeline replacement, pressure reduction for pipeline segments with a potential impact radius less than or equal to 150 feet, or alternative technology. If pipeline operators do not have the necessary information or records to confirm MAOP, they must use one of these methods to verify MAOP.
• Subsea PLEM (Pipeline End Manifold) is a termination unit that serves as a connection point between multiple pieces of pipe in a subsea environment.

Managing Unpiggable Pipe: Full Episode Transcript

Russel Treat:  Welcome to the Pipeliners Podcast, episode 192, 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.

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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. 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 customized YETI tumbler to one listener every episode. This week, our winner is Mark Ledesma with Williams. Congratulations, Mark. Your YETI is on its way. To learn how you can win this signature prize, stick around for the end of the episode.

This week, Corey Richards, Regional Manager for Challenging Pipeline Diagnostics at ROSEN, is going to join us to talk about integrity management on so-called unpiggable pipelines. Corey, welcome to the Pipeliners Podcast.

Corey Richards:  Thanks, Russel. Pleasure’s all mine.

Russel:  Before we dive in, would you mind giving us a brief introduction? Tell a little bit about yourself and how you got into integrity management.

Corey:  Corey Richards, I’m working here at the ROSEN Group. I’ve been working in the oil and gas industry for about 15 years. 12 years of that has been in ROSEN, field technician originally, then working into technical sales.

Then to my current role, which is challenging pipelines, or unpiggable pipelines. Started this in Lingen in Germany at our research center for a number of years, looking after Asia Pacific and Oceania, and then moving back here to Calgary about two years ago, still focusing on unpiggables.

Really got into this industry, like many other people, following in my dad’s footsteps. He’s an old pipeliner, and I followed that same direction.

Russel:  What did your dad do in the pipelining space?

Corey:  My dad originally started out as a welder and then worked his way into welding inspector, chief inspector on the construction side, and then construction management, and also worked in the ILI side of it, too. Then he worked for Nova and then Transcanada, I guess, at the time, and then also consulting for the last couple years.

Russel:  Awesome. This is a business we tend to inherit from our parents. They pass the gene down.

Corey:  Yeah, whether we like it or not, right? [laughs]

Russel:  Right. Some of us, like myself, we have to search out this industry, and then once we find it, we don’t leave. Others of us are more fortunate. We find it through our parents.

Corey:  That’s exactly it. It’s a diverse industry. It’s quite interesting. It’s engaging, with lots of different avenues to work into. Once you’re in it, if you get bored, you can always go somewhere else and still be within the same industry.

Russel:  I can support your comment that it’s diverse, because I have found that, doing this podcast, you would think, after 200 episodes, almost, that I would have covered everything there is to talk about in pipelining, but I am quite certain that is not the case. It’s a lot more diverse than what you can cover in 200 episodes. It’s a big domain. It’s a big domain.

Corey:  You must be on your way to be an industry SME at this point.

Russel:  I know a whole lot about a couple of subjects and a little bit about a lot of subjects.

Corey:  The millwright of the pipeline industry.

Russel:  Exactly right, exactly right. I asked you to come on to talk about unpiggables, so I’ll just start with the simple question. That is, what’s unpiggable? What’s the definition? What does that mean?

Corey:  I think, when we look at unpiggable pipelines, most people are, I guess, maybe or maybe not aware we have our piggable pipeline network. What we mean here is pipelines where we have standard launching/receiving facilities, where we can insert an inline inspection tool that is free swimming, that will run through the line with product.

We’ll put it in the launcher and receive it at the receiving end. Now, these tools are going to be running with conventional operating parameters, so each one will need a certain amount of flow, a certain amount of pressure.

Some require products. Some require no product, or medium independent technologies. A lot of these lines — I’d say the large part of the main line network, at least — is piggable. You can put the tool in, runs with the flows, no problem.

Now, we have a large section — often, I hear 40 percent of the world’s pipelines are considered unpiggable — we have this large section of pipelines that are unpiggable. Why? It could be we don’t have launchers and receivers. Maybe we don’t have the ability to add launchers and receivers, or we don’t have flow or pressures that we would need to launch conventional inline inspection tools, or maybe there’s just some mechanical design parameters in that particular pipeline that would inhibit a conventional ILI tool to run through it.

Russel:  Is that typically the older pipelines that would be unpiggable, or are there other categories of things that are unpiggable?

Corey:  You just see it a lot, I would argue, in older lines. Simply, these weren’t set up for conventional pigging, but it’s not uncommon to build new lines where you might have operational conditions such as high flow, where you can’t run conventional technologies, or extremely high pressures, or maybe you just need to work the pipe through a certain area.

Conventional tools wouldn’t be able to run through that type of piping network. Tight radius bends that are back to back, back to back, or even…Often you see these miter bends. These cause some issues. I’d say, like you said, more often, the older lines, but we still see these as common issues in new lines as well.

Russel:  I want to frame up this conversation a little bit, too, because I think, at least before we started having the conversation, getting prepared to record this episode, I thought unpiggable just meant you can’t inspect it, but that’s not really the case.

It’s really, you have these things that you can’t run a tool through, and then you have things that are more standard. Then this whole room in the middle where I can run a tool, but it’s going to require some extra work or thinking. Is that a fair way to frame it?

Corey:  Yeah, no, I think that’s exactly it. For a number of years, we always just had these two categories, piggable/unpiggable. The piggable was just that — the stuff that you could just get after.

Then you had this other network of pipe that you just didn’t really know what to do with. For the most part, that stuff often was shelved. We just said, “Okay, we’ll look at that another time, when we have time to look at it, or regulatory demands drive us to that direction.” The reality is a lot of that pipe is piggable. It’s just more of a challenging type of inspection, where we have to use specialized technologies, or maybe modify operating parameters, or even small modifications on that particular asset.

Russel:  What are some of the strategies or techniques that you might use for these challenging situations?

Corey:  If we look at free swimming tools, for example, all of these tools, they’re being essentially pulled through the pipeline. The product pushes it from the rear. We have some bypass around the tool, which then pulls the tool through the pipeline.

What we do is that particular tool has some sealing elements. Polyurethane will then seal it to the pipe wall, holds in that product, and then we pull it through the line. Now, in a conventional pipeline, we need to look at things we can do to that tool to modify it to make it run a lot more smoothly.

If we start to look at a low pressure pipeline or a low flow pipeline, we focus on certain tool elements such as tool centralization, sealing capabilities, friction reduction, weight optimization, all with the goal of reducing the overall friction components of the tool.

It makes it run a lot smoother, so you have a smaller differential pressure requirement across the tool to push it. It makes it a lot easier to go through bends or through certain types of installations, which would cause what we call speed excursions, which will then cause some degraded data issues.

Then, we can apply these types of technologies in low flow pipelines or low pressure pipelines, pipelines we typically wouldn’t be able to even discuss putting a tool in years ago, and if we did, the data would just be terrible.

Nowadays, we can get these lines inspected with a non-conventional free swimming tool. Will still give us ideal data quality. Then we still have lines where we have no flow, no pressure, and we look at more robotic, self-propelled solutions.

Russel:  Talk to me about self-propelled, because frankly, that’s a brand new concept to me. What does that mean for a tool to be self-propelled, and how is that accomplished?

Corey:  As I mentioned, the typical tools are going with the product. The product is pushing it to the endpoint. Now, with the self-propelled tools, you rely on a propulsion module, typically at the front of the tool, to actually pull the tool itself through the line. It may have wheels. It may have some track design. Anyway, something that will grip onto the pipe wall and essentially drive and pull that tool to our designated endpoint.

Within these types of technologies, we have tethered and untethered technologies, and tethered being something with a cable. We can either pull that back or use that for some type of communication. Then the tetherless tools, of course, don’t have this, but they also don’t have that added contingency as well.

Russel:  You said pull back. You’ve got to slow down a little bit, Corey, and help me, because I’m a bit of a novice here. When you say pull back, are you talking about I load a tool, let it run out, and then I use the tether to recover it?

Corey:  Yeah, there’s a little bit of both. Some of the tethered solutions in the market, or some that we actually utilize as well, you would drive the tool to the endpoint, and then we would pull it back with the tether on it.

Other tools have drive mechanisms in the front and the rear of the tool so that it can actually drive back to the starting point. However, these robotic and these autonomous solutions are still relatively new to the market.

The question typically arises, “Okay, what happens? What happens if something fails? If the tool fails, how do we get this out?” Conventional ILI, we have some strategies there. We can try to push it out with some more product, maybe put something behind it to bump it and then try to push it back up, but when this fails, what do we do?

One of the most common ways to get one of these tools out now is with a tether. We have this contingency tether often on these tools that we can now say, “OKay, tool completely fails, we can now pull this out to the entry point.”

Russel:  How long of a tether can you run?

Corey:  Ah, [laughs] loaded question. We always joke around. You get the answer that it depends. This is definitely one of those, it depends. You have a lot of different factors. You have your dry lines and your liquid lines. When you have a liquid line, we can typically travel farther distances. The reason being is we can have elements within that tether itself that make it neutrally buoyant, so it floats through the pipeline.

What happens is, when the crawler is pulling this tether, in a dry line, it’s essentially dragging this. The longer you have to drag the tether, the more weight that tool is going to see, and it’s going to get more and more difficult to pull it the farther you go.

Another issue we tend to have, of course, is bends. Every time we add another bend within the line, we’re going to add more tension onto that cable. Eventually, we’re going to get to a point where we can no longer pull the cable itself, which is going to get caught up in these bends.

In a liquid line, again, we can have cables that then essentially float through it. We have higher bend capabilities as well, too. We can go through more bends. Tether flows through the line, makes it much easier, and we can go farther distances.

We have tether units that can go up to 12 kilometers, and we can also loop them together to go up to 24 kilometers. These would be liquid lines with a low volume of bends, and we can typically see these distances.

When we start looking at a dry gas line where we’re trying to run these types of tools, you’re fairly limited. I would say you’re probably between 5 and 10, depending on if the bends are horizontal and vertical.

Russel:  Interesting. You mentioned that some of these have drive units on them, and some of them have drive units on both ends. I would assume those drive end units are also battery-powered. Then that also becomes another limiting factor is how far can you go before the batteries run out?

Corey:  This is exactly it, yeah. This goes back to the tethered and untethered tools. With a lot of the tethered tools that we’re utilizing, we do have some copper wiring in there to either charge the battery units as we operate through the line, or in other cases, we use this to solely operate the tool itself, so it’s running off of shore power.

In the tetherless systems, of course, yeah, you’re going to be limited to the battery vessels you have on board of it. I’ve seen some systems in the market that have some external power charging stations. That’s outside of our wheelhouse, so I can’t really comment on how well that’s working, but for the most part, we see these running with a tether, or just off the batteries they have.

Russel:  Interesting. I’m trying to process this, Corey, as I’m listening to you talk. I have this whole thought in my mind about, well, “Okay, there’s the issue with the tether itself and how long can I run out the tether.” That’s going to be dependent on the fluid that I’m working with and the nature of the tether itself.

I would assume that a tether that I just used to pull and retrieve is probably lighter than the tether that I’m using to provide power or communications. It’s like everything else. The minute I start knowing some of the details, it starts getting pretty dang complex.

Corey:  Yeah, it’s quite complicated. [laughs] These systems, I would say, are fairly niche. They’re typically being utilized for shorter lines. I would say more common, at least more common for us initially, has been in offshore applications, where you simply would only have a single access point, and you’re going to a subsea PLEM or something like this. This is initially for us where we would use these more commonly. We do use them onshore as well, too. Yeah, a very niche situation where we’re using them.

Russel:  Yeah. [laughs] No doubt, no doubt, right? It’s very niche. That addresses one whole domain of challenging. The places where I need to run a tethered tool, either because of how I have to load the tool, or how I have to recover the tool, or how I have to drive the tool. All those things would be issues that might drive me towards something that’s tethered.

Then, what other kinds of strategies might there be beyond what we’ve talked about so far? Are there other kinds of approaches that people might think about when they’re looking at, “How do I get this particular piece of pipe inspected?”

Corey:  I think one, a large, common issue we’ve seen, especially over the years, and now, with some of the PHMSA changes towards MAOP validation has been how do we manage these lower flow and lower pressure lines?

What we’ve established are low friction-based technologies for these types of systems, so we can run in extremely low pressure environments while reducing the speed excursions that we see throughout the line, ensuring better data quality.

We can start applying these through different types of technologies as well, too. Primarily, we see with MFL, but EMAT is making some investment in here. Then we’ve also started to broader these out into multi-diameter pipelines, where we have 16 to 20 inch, for example, ranges that we’re working in, or even dual diameter lines, 10 and 12.

We’re building up a lot of these technologies, so expanding on what was typically available in the free swimming market, and pushing that through to have a larger portfolio, so to say, for these solutions.

Russel:  Okay, again, I’m going to play this back to you, just so that I make sure I understand what you’re saying. Basically, what you’re talking about is tools, which the diameter of the pipe that they will work within is dynamic. I could start in a 20-inch pipe, and then the tool will actually make itself small and move into a 14-inch pipe, that type of thing.

Corey:  Exactly, yeah. We’ve had these technologies, at least within ROSEN, for a number of years to handle multi-diameter pipelines. Where we’re seeing further advancements in these are now, we’re adapting those similar types of technologies into more complex operating conditions in lower flow and lower pressure lines.

Russel:  Okay, I got you. Yeah, that would make sense, because the minute you start trying to do that in a low differential pressure, when you get into the narrower line, you’re moving a heavier tool.

Corey:  Yeah, exactly. What happens commonly in these low pressure lines, for example, is it’s not uncommon for tools just to get hung up on random things in the line. Then they have to build up this differential pressure to, of course, push through it.

In a higher pressure line, you typically have a lot of cushion in front of the tool to slow it down, and you have a lot of pressure behind it to push it through.

In these low pressure lines, as soon as you get hung up on something, you lose that head pressure. It takes you a little bit longer to build up that differential pressure behind it, and then you get the speed excursion. The tool shoots out at a high velocity, and then we end up having degraded data once we hit a certain peak of velocity.

Depending on how high that goes, of course, you’ll have your downward trend for when it slows down back to its normal velocity operating range, where we can collect better data quality again.

Russel:  Yeah, I’m just thinking about just the operating realities of that. If you go to all this extra effort to run one of these tools, and then you have a bunch of speed excursions or whatever, because it’s getting hung up, and then you analyze the data on the back end, and you go, “Yeah, well, that’s not good enough. We’ve got to run it again,” that can’t be fun.

Corey:  No. To be fair, I guess, that’s how it had been for a number of years. This was an accepted issue, just in gas lines in general. Speed excursions are an everyday thing, and this is something we’ve just grown…I don’t want to say, “accept.” That isn’t the right word, but they were fairly commonplace. As these technologies have now evolved, the speed excursions in normal operating gas lines, I would argue we can more or less solve that.

Now, what we can do, and what we’ve seen in these extreme environments, has been extremely impressive.

Russel:  Interesting. What is driving the ability to be able to do this, and do it with more predictability?

Corey:  In general, just overall evolutions in tool design. Of course, as things have evolved, we’ve been able to do more with the tools, lighter-weight kind of designs. We’ve been able to slim down the overall weight of the tool by doing this.

We’ve also added certain low friction elements, so the tools are primarily running on wheels. We only run on rolling friction. Just things that we’ve learned over the years, adapting them, putting them in different applications, and just building on that knowledge base, and advancing the tools every time we get some more data from the previous iteration.

Russel:  How much of it is just dropping the weight of the batteries and dropping the weight of the materials you use to build the tools?

Corey:  Some of that, for sure, is significant. When you start to get to small diameter tools — 12 inch, for example — it’s common to have three or four body tools. Just developing more, smaller electronics that are pulling less battery life, putting this all into a single canister, and dropping that weight is significant. Polyurethane is also a large contributor to the overall friction and run performance as well, too, so optimizing that has actually made a big difference.

Russel:  Yeah, interesting. [laughs] Just again confirms my notion that everything’s easy until you know enough about it.

Corey:  Right? [laughs]

Russel:  Yeah. In general, what are the PHMSA regs around so-called unpiggable or challenging run types?

Corey:  It’s not my strength. This isn’t the U.S. regulations, but sitting on the Canada side. From what I understand, though, PHSMA is more less defining unpiggable as if the operation limits of these particular technologies, including operating pressure, low flow, or availability of technologies for certain pipe diameters, can prevent the tool from running through the line safely or accurately to perform the assessment, they categorize it as an unpiggable.

It’s not even really defined. It’s more of “this is an industry term.” They’re not redefining it. It’s leaving it as, “How does the industry play this as an unpiggable” rule, which I think then leaves a lot to how do you then justify or how do you then assess these lines as an operator? It’s quite difficult.

You can put a pipeline into the unpiggable category and say there’s not much I can do with it, but I think the reality is there is a lot of technologies — especially now for gas operators that are looking for this MAOP validation — that they’ll need to be performing here.

Previous pipelines that you wouldn’t be able to run an MFL tool, for example, because of pressure and flow, well, these technologies are here nowadays. I think it’s going to push a lot of operators to start looking more into “What is non-standard? What can I do for these lines? Can I develop something?”

Companies like ROSEN, for example, it’s not uncommon for us to build a custom tool for a particular pipeline or a particular network to meet the challenges of those lines. These things are available. I think there’s going to be a lot more pressure to look at these types of solutions, and they’re around.

Russel:  I guess I’m getting muddled in my thinking here. What’s washing through my brain here is I have those things that are clearly unpiggable, just taking a simple example, just geometry causes it to be unpiggable. Then, I have to have some other kind of program, other than running ILI, to do my inspection. Either digs or materials properties or something to allow me to perform my risk assessment on that portion of my system.

Then it becomes a question of what is the more effective way to manage that pipe, come up with a way to pig it, or continue to do whatever I am doing other than pigging?

Corey:  Yep, I think that’s accurate. I could be misinterpreting it. My understanding is that if you’re unable to do any type of inspection work, then you’re pushing to doing some type of…doing a hydro test or something like this, which is, typically, that makes most gas operators cringe, for fair reason.

I think, when you start looking at the availability of some of these types of technologies that maybe people weren’t aware of, they become a lot more attractive, especially when there’s a lot more understanding that they’re available, and they’re here.

Russel:  That leads me to the last question that I wanted to ask you. That is what do you think a pipeline operator ought to take away from this conversation we’re having? What are the key things that a pipeline operator ought to be aware of?

Corey:  It’s the thing that I always throw out that when you’re assessing any of these lines, and you’re finding it that maybe your selected vendor can’t inspect it, search around. Speak with other vendors, or even work with that particular vendor to see if there’s something you can develop, or if there are modifications that could be made.

I think a lot of people would be very surprised on what’s available outside of maybe that preferred vendor, or maybe what your vendor is doing, or maybe what your actual preferred vendor could be doing for you. Can they develop something? Can they modify something?

There’s a lot more that can be done, simply just having more detailed conversations and supplying more of this data to your vendors, letting them understand exactly what your problems are, and really working together to try to solve that solution. I think you’d be surprised on what could be done for these unpiggable lines.

Russel:  Perfect. I think that’s certainly my takeaway here, is that, like everything else in integrity management, things are problematic. You’ve got to understand what’s the risk associated with this particular line from an operating perspective, and then what is my approach to inspecting it?

I think one of the things that’s really clear to me in this conversation is there’s a host of tools out there that are outside of what you see in 80 or 90 percent of the cases.

Corey:  Yeah, for sure. I’m being promotional here, but I feel fortunate at ROSEN where we have a lot of these technologies. I’m spoiled in the sense that I’m able to look at we have a lot we can do on the traditional side.

Then, when we start to focus on the unpiggables, the amount of solutions that we have available, or that I have available to me to utilize is fantastic. From robotics and self-propelled to these low friction technologies, and then to the different types of measurement technologies that I can incorporate into these, it’s pretty impressive what we can do for these types of assets.

Russel:  Awesome. Listen, Corey, this has been a great episode. I have to tell you, you’ve made my head hurt a little bit. Hopefully, this has been educational for those that are listening.

Corey:  It’s been great for me, and my wife says the same when she talks to me, so I don’t know how to take that. Her head hurts as well, too. [laughter] No, I appreciate it. This was a great experience, and I really appreciate you giving me the time today.

Russel:  All right, Corey. Well, we appreciate it. You take care now.

Corey:  Thank you. You, too.

Russel:  I hope you enjoyed this week’s episode of the Pipeliners Podcast and our conversation with Corey. 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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