In this month’s edition of the Pipeline Technology Podcast sponsored by Pipeline & Gas Journal, Stephen Newman of Halliburton discusses his article in P&GJ talking about the capabilities of InnerVue™, a Non Intrusive Pipeline Inspection Method for Unpiggable Lines, recently developed by Halliburton.

In this episode, you will learn about the technology behind InnerVue, specifically the survey methods and their assistance in risk mitigation and pigging campaigns, the key factors that go into this non-intrusive inspection approach that reduces downtime for pipeline operators, and the future developments of the technology.

Unpiggable Pipelines: Show Notes, Links, and Insider Terms

• Stephen Newman is Product Champion for Halliburton Pipeline and Process services. Connect with Stephen on LinkedIn.
  • Halliburton delivers a full suite of global pipeline services to the plant construction, commissioning, maintenance, and operating industries.
• Pipeline & Gas Journal is the essential resource for technology, industry information, and analytical trends in the midstream oil and gas industry.  For more information on how to become a subscriber, visit pgjonline.com/subscribe.
  • Read the referenced Pipeline & Gas Journal article, “Halliburton Develops Non Intrusive Pipeline Inspection Method for Unpiggable Lines,” in the August 2021 edition of Pipeline & Gas Journal.
    • Learn more about the first annual Pipeline & Gas Journal Awards, set for November 18, 2021, in Houston, Texas.
• InnerVue™ is a fast, accurate, and low-risk solution for locating and quantifying pipeline problems. InnerVue detects flow inefficiencies caused by wax, scale, asphaltenes or hydrate deposits. It also locates blockages, stuck pigs, and quantifies leaks or unsanctioned hot-taps. It requires minimal setup with low operational impact and has fast data collection, with preliminary results available within hours.  
• 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).
  • Unpiggable/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.
  • Piggability refers to the ability for a pig to successfully traverse the pipeline from launch to receipt.
• Pressure Wave Analysis analyzes a pressure wave (the pulse) created at one end of the pipe and the returned reflected signature wave corresponding to features in the pipe including barriers to flow, changes in medium, and leaks. Blockage positions, deposit profile, and leak characteristics are then estimated by analysis of the signal response.
  • Thomas Redares of Halliburton discusses Pressure Wave Analysis in more detail in this presentation.
• Leak Detection Pressure Analysis is a method of leak detection based on the analysis of pipeline pressure variations. When a product breaches the pipeline wall there is a drop in pressure at the location of the leak followed by an increase in pressure a few milliseconds later. The resulting low-pressure expansion wave travels at the speed of sound through the liquid away from the leak in both directions. The time recorded at each end of the monitored line or segment is used to calculate the location of the leak.
• Negative Pressure Wave occurs when leaks develop in a pipeline causing the gas density near the leaking point to decrease rapidly. This phenomenon results in a negative pressure wave, which propagates through the pipeline from the leak point.  
• InnerVue Static Analysis An InnerVue static analysis survey is used to locate blockages within pipelines or wellbores. Static analysis is performed by inducing a negative pressure wave in a pipeline or wellbore and then analysing the response of the pipeline system. The negative pressure wave travels along the pipe or well bore to the blockage and reflects a signature response back to a data recorder at one end of the pipeline. Distance to blockage can be calculated from the transit time of the pressure wave and the acoustic velocity on the system.
• InnerVue Dynamic Analysis: an InnerVue dynamic analysis survey can be used to profile deposition along the entire length of a pipeline or wellbore.  The analysis can also be used to locate leaks.  Dynamic analysis is performed by recording the pressure response in a system when all flow is stopped. The pressure response is analysed using Halliburton’s proprietary software. Depositions can be plotted with an accuracy of +/-3mm.
• Acoustic Velocity is defined as the rate at which a sound wave travels through a medium. Unlike the physicist’s definition of velocity as a vector, its usage in geophysics is as a property of a medium: distance divided by travel time.
• Water Hammer is described as a phenomenon that can occur where valves are used to control the flow of liquids or steam. Water hammer is the result of a pressure surge, or high-pressure shock wave that propagates through a piping system when a fluid in motion is forced to change direction or stop abruptly.
• Inline Inspection (ILI) 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.
• Hydraulic Diameter is the effective cross-sectional area of a pipe or wellbore through which a fluid can flow.  
• Axial and circumferential magnetic tools evaluate metal loss going down a pipeline. Axial refers to when the flux runs along the pipeline and circumferential refers to the flux running around the pipe.
• Hydraulic Modeling is a form of physical or numerical modeling used to investigate design and operation issues in hydraulic engineering. 
• SCADA (Supervisory Control and Data Acquisition) is a system of software and technology that allows pipeliners to control processes locally or at remote locations.

Unpiggable Pipelines: Full Episode Transcript

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 Treat:  Welcome to the Pipeline Technology Podcast, episode 15. On this episode, our guest is Stephen Newman, product champion at Halliburton. We’ll be talking to Steve about his article published in the August 2021 Pipeline & Gas Journal entitled “Halliburton Develops Non Intrusive Pipeline Inspection Method for Unpiggable Lines.”

Stephen, welcome to the Pipeline Technology Podcast.

Stephen Newman:  Thanks for having me on.

Russel:  Before we get going here, maybe you could tell us a little bit about yourself and how you got into pipeline, and your current role.

Stephen:  I’ve been working on pipelines for about 20 years now. I’m originally from Ireland. I moved to Aberdeen, Scotland, to study, which is the oil capital of Europe, as many people know, so I did a master’s degree in mechanical engineering there and started work.

I started out doing finite element analysis of lateral buckles in pipelines in a design house. I did that for quite a few years, looking at how pipelines heat up and figuring out if they buckle or not, how thick they would need to be, and how to restrain them. Then, moved on to subsea projects, doing things like architecture design right through to installation and commissioning.

More recently, I’ve been specializing in pigging, so that’s pre-commissioning, maintenance decommissioning, that sort of thing.

Russel:  [laughs] I always get a kick out of how people get into pipelining. Quite a long time ago, I was taking master’s level classes doing finite element analysis and structural engineering, so we probably have a bit in common there.

Stephen:  I spent quite a few years doing that working on Abaqus, setting up models of pipelines on the seabed, heating them up, and seeing what happens.

Russel:  I’m the kind of nerd that would find that fun. That’s pretty awesome.

You’re currently at Halliburton. What’s your role at Halliburton?

Stephen:  At Halliburton, my role is product champion. That is basically developing new technology for the pipelines and process group. One of the technologies I’m working on is InnerVue, our non-intrusive survey technique, which we’re hoping to talk more about today.

Russel:  Exactly correct. You have a paper that was published in Pipeline & Gas Journal on this particular nonintrusive pipeline inspection method. The thing that caught my eye was unpiggable lines because that’s the topic of interest, I think, for a lot of people. Could you tell us a little bit about what is this technology, and how does it work?

Stephen:  It works on pressure wave analysis, so really nothing goes within the pipeline. What we do is we send pressure waves down the pipeline. Through interpretation of the response that pressure wave gives off different features in the line, we can identify things like blockages in the line. We can create a graph showing you the deposition level along the whole length of the pipeline.

Russel:  You’re going to define that for me, the deposition level.

Stephen:  Say you have something like wax, scale, asphaltenes in your pipeline. What we can do is send this pressure wave down the pipeline. It will reflect off all these different features, things like wax. From that, it gives us a picture of what is inside the pipeline along its entire length.

Russel:  I always say this like my particular expertise is not in integrity management, but I know enough about a lot of these things to be dangerous and ask dumb questions. How are you sending the signal, and how are you picking it up and interpreting it?

Stephen:  There are two different types of surveys we do. One is our static analysis. We use this for blockage locations. Say you have something like a stuck pig in your pipeline or some sort of collapse. What we do is we send a pressure wave down the line. That’s our static analysis.

The pipeline’s not flowing. We tie in, say at the inlet end, with our pressure recorder, and we bleed off a small quantity of gas or liquid from the line. That creates a localized negative pressure wave that’ll travel down the line, bounces off your blockage, say your pig. That’ll come back to you on topside through the end of the pipeline. Through timing that and having an understanding of the acoustic velocity in the line, we can tell you exactly where the pig is. That’s our static analysis.

We also do dynamic analysis, which is what you were just talking about there where we get a deposition profile, a profile of your wax deposits, along an entire length of the line. It’s a slightly different survey.

How we do that, we use our dynamic mode so the pipeline’s up and flowing, we need to have flow here. You close a mainline valve on the inlet to the pipeline. That creates almost like a water hammer effect, and a pressure wave travels down through the pipe. It reflects off all the different changes in diameter. As you get, say, more wax or scale buildup, it’ll reflect off that. It sends a signal back to our pressure recorder at one end of the pipeline, and through interpretation of that, we can tell you what the level of wax is along the entire length.

Russel:  It’s interesting. My expertise is more in leak detection, and negative pressure wave is used in leak detections applied differently. It sounds like it’s similar in terms of the kind of analysis you’re doing of the wave.

You’re actually listening to the pressure transmitter. This is really helpful on a podcast. I’m doing air quotes with my fingers. You’re “listening” to that pressure sensor, and you’re picking up the modulation of the pressure sensors that wave reflects back. Then you’re interpreting that to understand what’s going on. Very fascinating.

Stephen:  Yeah, that’s pretty much how it works. The leak detection is probably more similar to our blockage location, where you have a single wave travel along the line, and you measure the time it takes for it to arrive at one end of the pipeline. That gives you an idea of where your leak would be. It’s kind of similar to how blockage location works.

For measuring the deposition, yeah, it is similar, I guess, in that the pressure wave travels down the line. As it stops that fluid from moving, what was a frictional pressure in the pipeline turns into a static pressure, and that’s what reflects back to us. That’s how — through interpretation  — we can tell what the level of deposition is in the pipe.

What we actually do is we model the pipeline and we run a simulation of what a clean pipe would look like if we sent a pressure wave down it. Then we go out into the field, and we record actual data by stopping the flow and sending a pressure wave down. You compare the two. It’s through the difference between the simulation and the data that we’ve collected in the field that you can determine what the deposition levels are on the whole length of the pipe.

Russel:  Interesting. You’ve talked about things that would build upon the pipe, like wax. Are you likewise able to pick up features in the metal itself? Like if you’ve got internal corrosion or cracking or any of that type of thing, are you able to pick that up as well?

Stephen:  I think whenever you’re looking for that level of detail, you’re best moving towards an ILI tool. What we pick up is things like wax or scale or asphaltenes. Our signal comes back to us. We get one data point approximately every quarter meter.

If you had a feature that was, say a corrosion feature that was at a very specific point in the pipeline, there’s a chance that would be smoothed out. I think if we’re looking for things like that, you really need to move to a different type of tool like an ILI tool. But where InnerVue comes into its own is in preparation for these ILI runs.

Say you want to put an ILI tool in the pipeline that you haven’t pigged for a long time or you’ve got no idea what’s inside it. If you go out and do an InnerVue survey prior to that, you get a pretty good picture of what level of wax or scale or whatever it is that you may be worried about in that pipeline is before you put that tool within the pipeline or the first pig for a cleaning campaign.

Russel:  Yeah, I would assume you would be able to pick up deformation as well in the pipeline. Like, if there were dents or compression or things that are significantly out of round, I would think you could pick that type of thing up as well.

Stephen:  Yeah, we can definitely pick it up. Like I say if it’s very localized and we would struggle to pick it up with our dynamic surveys. But if it’s a serious kind of dent or deformation, like say 60 percent of the pipe, then we can even pick that up with our static surveys and tell you where it is.

Russel:  Yeah, that’s fascinating. I would think for offshore pipelines, in particular, this could be a pretty effective risk mitigation tool.

Stephen:  We find that risk mitigation is a big way in which our clients or operators are using this tool. It’s things like in preparation before a pigging campaign. You can confirm piggability before you put anything within the pipe. You get a significant reduction in the risk of a stuck pig.

One of the other things our clients use it for is tailoring pigging campaigns. Say you need to get a pipeline cleaned up, and you’ve got a pigging campaign planned, but it requires a shutdown to run the pigs through, you can significantly reduce the amount of lost production there in the time it takes that campaign to run by using an InnerVue survey upfront. It gives you an idea of how aggressive you can be with your first pig.

You can also perform surveys, as the pigging progresses, to see how effective the previous pigs have been and give you an idea of how aggressive you should be with the next pigs and potentially shave days off a pigging campaign.

Russel:  Yeah, which is no small thing.

Stephen:  It’s no small thing with the lost production, yeah.

Russel:  Yeah, absolutely. Absolutely. I’m reading through the article that you provided and I’m trying to think about the places where this would be most useful. I would think that certainly if you’re trying to locate a stuck pig, I could certainly see where that would be quite helpful.

But what kind of pipelines are going to have wax buildups or things where you need to be more deliberate about your cleaning campaigns and trying to scope that? I would guess the other thing you could do is you could run this from time to time to figure out if you need to do a cleaning campaign.

Stephen:  Exactly, yeah. We’ve seen some of our operators do that in the past. Instead of doing routine pigging, they can go out, and you can run an InnerVue survey to make sure that you’re getting a similar response to what you had the previous year. Or you can see that there’s been a buildup since you previously surveyed the pipeline, and you’re going to have to get out there and clean it.

It’s going to be production pipelines with oil flowing through them. Maybe they have a wax issue. Maybe they have an asphaltene issue, a scale issue. Operators tend to know about these and have routine pigging campaigns that they run for them, so it’s there where we can save them money by making those pigging campaigns shorter or potentially not even needing to run a pigging campaign at all.

Russel:  Yeah, I’m sure the first time you go to a customer, and you run this, and you say you don’t need to run this pigging campaign every year. You can run it every 18 months. They’re pretty ecstatic.

Stephen:  Yeah, absolutely. Or maybe we’d tell them that you’ve got a huge problem, they need to get in there and start pigging as soon as possible before it gets any worse.

Russel:  Right. Equally as valuable, right?

Stephen:  Yeah, absolutely. One of the times, whenever we tend to find the operators are happiest is with the stuck pig locating. If you have a stuck pig within a line, you have absolutely no idea where it is. We can go out there and we can survey it.

We can usually be on-site within a couple of days and tell them pretty much where the pig is. Then they can go in and cut or do whatever remediation campaign that needs to be done to get the pipeline back on track.

Russel:  Likewise, a very big deal. Likewise, a very big deal.

Stephen:  One of the case studies that we often talk about was one of our operators had an ILI tool get stuck in an ethylene pipeline, so the ops and engineering team just couldn’t agree on where it was. They knew they had to cut the pipeline to get this tool back and they asked for an InnerVue survey. We headed out on site. I think we were there within a couple of days. 

It was quite a special case, this one. Because whenever we do our stuck pig locating, one of the key things we need to understand is the acoustic velocity in the pipe of the fluid. If we understand that really well and then we get a timing to the blockage and back, we can tell you exactly where the blockage is. If you don’t have a good idea of the acoustic velocity, it could get quite far out.

In this instance, the operator had two identical pipelines. One had a stuck pig in it, and the other one didn’t. We ran a survey in the pipeline that didn’t have the stuck pig in it and we bounced our signal off, a closed valve at the far end, which gave us a very accurate determination of acoustic velocity. We then performed a survey in the pipeline with the stuck ILI tool and managed to locate the tool within three meters. The operator went along, cut into the pipe, there was the tool. It was a huge win for them.

Russel:  Yeah, that’s amazing. I think it’s pretty creative, too. You were lucky in the fact that you had another pipeline you could use carrying the same fluid to determine that acoustic velocity.

Stephen:  Yeah, absolutely.

Russel:  Because getting that acoustic velocity in the ethylene is not a simple problem. [laughs]

Stephen:  No. A lot of this data is available out there, but if you have different pressures and temperatures you’re operating on, then it can change for a local scenario.

Russel:  Right, the fluid dynamics of ethylene are…I think the technical term would be bizarre. [laughs] It’s interesting that you could quickly come up with a creative way to get what you need in order to locate a pig like that.

Stephen:  Yeah.

Russel:  How else would you do it? How much pipe would you have to cut out if you weren’t able to locate it within a few meters?

Stephen:  That’s it exactly, yeah. We’ve seen operators in the past have been looking for it for quite some time. We run an InnerVue survey and identify where it is, and there it is whenever they dig up the pipe. There’s the stuck pig. It’s a great time-saver.

Russel:  I don’t know the answer to this question, and I don’t know that you would either, but how frequently do you get to the point you’ve got a stuck pig and you’ve got to cut it out? I wonder how often that occurs in our business.

Stephen:  Yeah, I couldn’t put an exact number on it. I’m probably a little biased because people phone me whenever they have a stuck pig. [laughs]

Russel:  Yeah, you probably have a better idea of what that number is than others.

Stephen:  Yeah, I see quite a few of them. There are different techniques that we can take. Obviously, cutting into the pipe is the last thing you want to do.

Russel:  Absolutely.

Stephen:  We do have our ops team that can have a look at different scenarios, different actions they can take for you to get the pig moving again. Those would be the first course of action. Cutting into the pipe is obviously the last one.

It depends on the pipe as well. If it’s quite a small pipe and it’s easy to rejoin, and sometimes if you know where the blockage is, you cut it. You take out whatever is blocking it and you join up the pipe again and you’re back up and operating.

But, if it’s a subsea line under a couple of thousand meters of water depth, that’s a very expensive option.

Russel:  Yes. If it’s a large pipeline, too, the same thing. If it’s a 36-inch pipeline, then it’s a whole different issue than if it’s an 8-inch pipeline.

Stephen:  Yeah, exactly.

Russel:  What do you think pipeline operators ought to know about this approach for non-intrusive inspection?

Stephen:  I think the key thing about the non-intrusive inspection is it’s almost zero risk. In the past, if you wanted to know what was in a pipe, you had to send something down it to get a picture of levels of wax asphaltene or scale or buildup of whatever within the pipeline.

Now you can do this pressure wave analysis, so it’ll give you a picture of what’s within the pipe. From that, you can streamline pigging campaigns, and you can minimize your production downtime. For the deposit profiling side, that’s the great win. Obviously, stuck pig or blockage, it’s pretty obvious what the advantages are there, getting back up and running as soon as possible.

Russel:  Know exactly where you’re stuck. Knowing where you’re stuck will open up a lot of opportunities in terms of methods and approaches for getting unstuck. Because if it’s near a valve, then there are things you can do that you can’t do if it’s not near a valve, and so forth.

Stephen:  Yeah, and more information, no matter what it is, always helps, doesn’t it?

Russel:  Absolutely. Absolutely. I noticed, too, that in the paper that you shared with me there are some pretty interesting graphics around locating, or diagramming, I should say, the level of deposit on the pipe where you show cutaways and you show some graphs and such.

I’m wondering to what degree can you locate the deposits from a 360-degree standpoint. You’re not going to see those deposits build up in a consistent way, I wouldn’t think. It’s going to tend to localize, probably at the bottom of the pipe.

Stephen:  Yeah, probably.

Russel:  Am I wrong about that?

Stephen:  No, you’re right. Absolutely. What the pressure wave analysis does, whenever you look at the conversion of this frictional pressure to static pressure, it gives you a hydraulic diameter. That’s effectively what we measure along the entire length of the pipe is a hydraulic diameter.

We can’t actually tell if all the depositions are on the bottom of the pipe or if it’s equally spread around it, what it’ll do is it’ll tell you the volume of it. Most operators know what their problem is whether it be wax or scale. They have a pretty good idea of how this deposition’s going to form within their pipe. What they actually got then is, it’s the total volume. You’re right. We can’t actually say where it is within the pipe [around pipe circumference].

Russel:  I was going to ask a follow-up question and that is to what degree does the location of that deposition matter if you’re planning a cleaning run? Do you really care where it is on the pipe wall?

Stephen:  No, I don’t really think it’s super important. I guess as long as you have an understanding of what type of problem you’ve got within the pipeline, if you have an idea of the volume at that position, then you know how to approach it.

If you’re expecting it all to be in the bottom, then you can size that first pig that goes in the pipeline appropriately. But if you’re expecting it to be uniformly around the wall of the pipe, then you would choose a different size of pig.

Russel:  I guess that comes from operator knowledge, having run the pigs and operated the line and knowing how whatever problem you’re dealing with, whether it’s wax or scale or whatever, understanding how it tends to form. Then what you’ve done successfully in the past.

It’s really not a matter of knowing all that because the operator would know that. It’s really more about just understanding how much do I have.

Stephen:  Yeah. The surveys are quite accurate. What we find from our experimental results is that we’re accurate to three millimeters on hydraulic diameter and 100 meters on location. 100 meters in axial length and three millimeters in hydraulic diameter. It gives a really good picture.

Russel:  How long of a run of pipeline can you get this information for? Is there a limit to how far a run you can analyze?

Stephen:  There is a limit. It’s getting pushed all the time. We used to have numbers that we would quote, but then operators would come out to us, and they’d say, “We’ve got this problem and it’s just a bit beyond that. Can we try?” We try, and it would work, so it tends to be growing as time goes on.

But for blockage location, for instance, I’ve had successful surveys at 100 kilometers. For deposit profiling, I can’t remember exactly. It depends if it’s liquid or gas, but certainly, 30 to 50 kilometers is achievable.

Russel:  Yeah, I wouldn’t think there are that many pipeline segments that are longer than that.

Stephen:  Yeah, that’s it. We often find there are valve stations in longer pipelines. If that’s the case, what we’ll do is we’ll go in and perform additional surveys at the valve stations. That gives the whole pipeline picture.

Russel:  What’s necessary to actually mount your equipment to the pipeline? What do you need to do what you do?

Stephen:  Okay. For a static survey, if we’re trying to find a blockage, all we really need is a quarter-inch fitting to tie into like an instrumentation point or something like that. It tends to be at the pig launcher or receiver where we’ll find one of these to be available.

We tie in with a tee. There’s a quarter-inch fitting. We’ll tie in our high-resolution data recorder to one side of the tee. Then for the other side, it would be a bleed-off point for creating that pressure wave, the localized pressure wave. We’re going to send this out then it bounces off the blockage.

For a dynamic survey where we’re doing our deposit profiling, it’s pretty much the same setup. It’s a quarter-inch fitting at one end of the pipeline, tie in our data recorder, and we still need the bleed point to be able to see it disconnected safely at the end.

Russel:  Yeah, interesting. That’s pretty trivial, frankly.

Stephen:  It is, yes.

Russel:  By doing that around the pig launcher, it’s simplified because those things are just easier to access on a pig launcher.

Stephen:  Absolutely. There’s always a tie-in point around there, or almost always. The other thing we need for a dynamic survey for deposition profiling is a fairly fast-acting valve to create the pressure wave that travels down the pipeline. Needs to be a mainline valve and it has to shut fairly quickly to be able to produce a strong enough pressure wave to get a signal to bounce back.

Russel:  Right. Like anything, there are always lots of details. Always lots of details. But to me, it sounds fairly straightforward.

Stephen:  Yeah. Yeah, it is. We send an operator out. Often they can be on-site for it in as little as six hours sometimes to perform these surveys. If you think about the acoustic velocity in a liquid or gas, 1,000 meters per second in a liquid. If you’re surveying a 20-kilometer pipeline, your whole survey is going to be done in 40 seconds. It’s pretty rapid. [laughs]

Russel:  Yeah, you’re going to spend more time hooking your equipment up than you are doing your survey.

Stephen:  Absolutely, yeah. The operator turns up. He ties in the equipment. You get the pipeline flowing nice and steady, staying. Close the mainline valve, wait about 40 seconds for a 20-kilometer pipeline. Open the mainline valve up again and you’re operating.

We do like to repeat it three to five times just to make sure there’s repeatability of the results and no noise, but it’s pretty quick to get done, yeah.

Russel:  I’m glad I asked that question, frankly, Steve, because that’s pretty compelling. Right?

Stephen:  Yeah.

Russel:  Not only is it not intrusive to the pipeline itself. It’s fairly non-intrusive to the actual operation.

Stephen:  Yeah, there’s really minimal disruption.

Russel:  That’s pretty fascinating. It’s not a lot of operating cost to associate with doing this.

Stephen:  No, not at all. To be honest, most of the work is done back in the office. The operator collects the data and then has to take the data off the data recorder. He’ll send it back onshore for analysis. There’s quite a lot of analysis work to be done. It takes a couple of days to a week to turn around a report to see what’s inside the pipe. The blockage location can be run a lot faster.

Russel:  Yeah, that’s the nature of pipelining right there. You go out in the field, you grab some data, and then you spend the time you need to figure out what that data is telling you. That’s just the nature of being a pipeliner. To be a good pipeliner, you need to be a bit of a data nerd.

Stephen:  Yeah, totally. [laughs]

Russel:  You maybe don’t need to, but it’s certainly helpful. If you don’t like wading through loads of data and doing analysis, then maybe pipelining is not the right thing for you.

Stephen:  Absolutely.

Russel:  Certainly not on the integrity side, anyways.

Stephen:  Yeah. There are a few other things that we’re developing the technology into. We can also see leaks in pipelines. If you have a long subsea pipeline with a leak in it and you’re not quite sure where it is, we can run one of our dynamic surveys and we can pick up that energy loss from the leak with the pressure wave.

It also comes in handy in a long land pipeline where you don’t have to walk that line or whatever, and you’ve got a leak, you don’t know where it is. You can run one of these InnerVue surveys to see where it is. The other thing we can do is we’ve developed our static analysis, the blockage location. We’re developing that into live pig tracking.

Say you’re running a pigging job and you want to know your pig is still moving. You want to have an estimated time of arrival. We can live pig track and give you things like pig velocity by using this technology. That’s without having to have pingers or whatever, sensors, senders, receivers on the line to see where it is.

Russel:  Yeah, that could be pretty powerful, particularly for folks that are running pigs frequently.

Stephen:  Yeah, especially for problem pipelines. It’s a huge bonus for the operator. We’ve seen pigs get stuck in pipelines in the past and put a remediation plan in place to hope to get it moving. Maybe you’re sending another pig in or you’re putting a gel pig in after it trying to get this stuck pig to move. You can use these InnerVue surveys to confirm that it has actually worked.

Once it starts to move, you can run the surveys and you can see the pig actually moving along the pipeline. You get a pig velocity, you can get an estimated time of arrival. You can also see if it stops moving and you maybe have to take another course of action.

Russel:  Can you monitor that in real-time as the pig is moving? Are you getting a data point once a minute? Once every few minutes? How frequently can you get a data point when you’re doing something like that?

Stephen:  Currently, we could probably get a data point every couple of minutes. But this is one of the things in our technology roadmap. We’re trying to develop this into a kind of live tracking system.

Russel:  Yeah, it’s interesting. I’m aware of other kinds of live tracking where you’re basically doing pressure analysis and doing hydraulic modeling to understand the location of the pig. Just taking data off the SCADA system and watching pressures and flows and, based on that, knowing where the pig is.

Those can be fairly accurate and fairly real-time, but the idea of doing it with direct signal detection is kind of compelling, particularly if you could move it in real-time and see the pig velocity. I could see a lot of value in something like that, particularly in a pipeline with a lot of elevation change, where you’re trying to maintain speed. You’re trying not to go too slow or too fast.

Stephen:  Yeah, it could be used for that, too. Especially gas pipeline networks. Maybe you’ve got a network with different usage at one end, and you’re pumping in at one rate, and you’re taking out at different rates, and you want to try and control pig velocity whenever you’re doing a pigging campaign. You can use it for that, too.

Russel:  Yeah. That would be very interesting. This is fascinating to me. There’s a whole conversation going on in my head that we’re not having on the microphone because I’m thinking about other ways you might apply this and what the value would be.

This is one of those that is a little outside my expertise. I know enough about negative pressure wave and leak detection and how that works. I can visualize how this works. Mathematically, it’s a very similar kind of thing, approach-wise. But the application is quite different.

Is there anything you’d like to offer the listeners as a windup comment for this conversation?

Stephen:  I think we’ve covered a lot of topics today. It’s been great to speak with you. Yeah, it’s great just to get that information out there and tell more people about our InnerVue pressure wave analysis.

Russel:  Yeah. Steve, I’ve really enjoyed this. I’m probably not talking as clearly as I might because I’m thinking pretty hard about the stuff you’re telling me. But this is a completely different kind of tool than what I’ve heard about in pipelining.

I’m always fascinated by just how many different tools are available to pipeliners to solve different kinds of problems. I’m really glad we did this, and thanks very much for taking the time and sharing the information.

Stephen:  Yeah, all right, Russel. Thanks for having me on the show.

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Russel:  I hope you enjoyed this month’s episode of the Pipeline Technology Podcast and our conversation with Stephen.  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 pipelinerspodcast.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 pipelinerspodcast.com or reach out to me on LinkedIn. 

One last thing. Mark your calendar for November 18, 2021, in Houston, Texas, where the Pipeline and Gas Journal is going to present its first annual Pipeline and Gas Journal Awards, honoring midstream energy’s leading innovations and outstanding personal contributions to the pipeline industry. Thanks for listening. I’ll talk to you next month.

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Transcription by CastingWords