This month’s Pipeline Technology Podcast episode sponsored by Pipeline & Gas Journal features Denise Earles of Pipesurvey USA discussing her company’s 27-day-long ILI run and how they worked through low pressure and low flow obstacles to produce accurate results.

In this month’s episode, you will learn why the run took 27 days and how low pressure and low flow caused other issues, such as paraffin buildup and having to calculate the batteries for the ILI tool to run properly over that long period of time.

Inline Inspection: Show Notes, Links, and Insider Terms

• Denise Earles is an ILI Applications Engineer at Pipesurvey USA, an INVACARE Partner Company. Connect with Denise on LinkedIn.
  • Pipesurvey USA, LLC is a partnership founded in 2019 between Pipesurvey International and INVACOR to bring world-class, proven in-line inspection tools and software to the U.S. market. Together, Pipesurvey USA and INVACARE offer a full suite of pipeline integrity services, either stand-alone or as total integrity solutions with one team, one quote, and one invoice.
  • Read Denise’s article published in Pipeline & Gas Journal.
• 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.
• R&D stands for research and development.
• Pipeline Pigging and Integrity Management Conference (PPIM) is the industry’s only forum devoted exclusively to pigging for maintenance and inspection, as well as pipeline integrity evaluation and repair. The event draws engineering management and field operating personnel from both transmission and distribution companies concerned with improved operations and integrity management.
• 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.
• IMU (Inertial Measurement Unit) measures the pipe curvature using a combination of accelerometers and gyroscopes.
• Pig Trap is a tool consisting of a launcher, receiver, and a cylindrical device, or pig, that travels the length of a pipeline by being pulled by a string or using the force of a fluid flowing through the line. 
• Paraffin Wax is a component of crude oil that builds up and has drastic negative effects on oil production and refineries. These paraffin are alkanes with a high molecular weight which have a choking effect on crude oil wells. Over time, these build-ups of deposits cause a decrease in production capacity and ability.
• PHMSA (Pipeline and Hazardous Materials Safety Administration) is responsible for providing pipeline safety oversight through regulatory rule-making, NTSB recommendations, and other important functions to protect people and the environment through the safe transportation of energy and other hazardous materials.
• Mega Rule – The rule, initiated over 10 years ago, expands the definition of a “regulated” gas gathering pipeline that is more than 50 years old. It will—for the first time—apply federal pipeline safety regulations to tens of thousands of miles of unregulated gas gathering pipelines.
• Magnetic Flux Leakage (MFL) is a magnetic method of nondestructive testing that is used to detect corrosion and pitting in steel structures, most commonly pipelines and storage tanks. The basic principle is that a powerful magnet is used to magnetize the steel. In areas where there is corrosion or missing metal, the magnetic field “leaks” from the steel. In an MFL tool, a magnetic detector is placed between the poles of the magnet to detect the leakage field. Analysts interpret the chart recording of the leakage field to identify damaged areas and to estimate the depth of metal loss.

Inline Inspection: 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 23. On this episode, our guest is Denise Earles, with Pipesurvey USA, an INVACOR company. We’re going to talk to Denise about her Pipeline & Gas Journal article titled, A 27-Day ILI Run: A Case Study of a Low-Pressure, Low-Flow Line.

Denise, welcome to the Pipeline Technology Podcast.

Denise Earles:  Thank you. I’m happy to be here today. Thanks for having me.

Russel:  Before we dive into this subject, maybe you could tell us a little bit about yourself and how you got into pipelining. How you ended up becoming an ILI engineer.

Denise:  Like most things in life, it was kind of accidental. I became an engineer originally because I wanted to solve problems, and I liked being able to take really big problems and break them down into small pieces, and achieve what seemed impossible at the beginning through that.

I originally started my career doing R&D work with automotive and then went into some circuit breaker design. Then being a good Texas girl, I ended up back down in Texas doing R&D projects for downhole oil and gas.

I found myself with my dream job running big projects and mentoring a bunch of engineers, and found myself bored. I decided to do some shifts and went to get into some bigger picture information about our industry.

At that point, I moved into some marketing roles, I did some international management experience, and then I ended up in a commercial role in ILI doing technical sales. Then from there, I’ve just found my home, and now I’m back doing engineering in ILI.

Russel:  It’s funny, Denise. As I listen to your story, it’s not unlike mine. I like people, and to do anything meaningful, you have to work with teams and build teams and all that. If I don’t get an opportunity every once in a while to get my teeth into something really geeky, I’m not a happy camper.

Denise:  Yes.

Russel:  I need a nice balance between the technical challenge and problem, and working with a team.

Denise:  Me too.

Russel:  It sounds like your background is not much different than that.

Denise:  Yeah. Little bit of everything, whatever piques my interest at the time.

Russel:  I asked you to come on to talk about your paper that you presented at PPIM on a 27-day-long ILI run. What about that particular project made you think that that might be a good opportunity to write a white paper?

Denise:  Just listening to the sound of it, a 27-day run. Most of my runs are 8 hours or 12 hours. The longest ones are usually 20 or 24 hours, so 27 days is a little bit ridiculous.

Russel:  That’s what I was going to say. That’s exactly what I was going to use. It’s ridiculously long.

Denise:  Yeah. With that, in order to make modifications to make that work, you actually get into a lot of the physics of the tool and friction, how you reduce friction, how you reduce bypass. You have all the issues with the batteries. You’ve all the issues with the memory on the tools, etc.

It was such an interesting project for me, and I thought that other people would find it interesting as well.

Russel:  What caused that tool run to take 27 days to run that tool?

Denise:  It was the low flow of that particular offshore line. This is an offshore line in the North Sea off the coast of the Netherlands. The well was in the very last phases of its life, so it’s producing very, very low volume and very, very low pressure, a mixture of oil and water basically.

Even though it was at the very end stages of its life, the pipeline still needs to be regulated. Because it was feeding into a storage terminal on the other side, there wasn’t any way to supplement any of that flow, so you just had to do what you had to do.

Russel:  That all makes sense. I would imagine that because it was a producing well, and because it was under sea, and because it was old. There were other challenges related to all those factors as well.

Denise:  There is always some challenges related to offshore pipelines, especially the ones that are old, that aren’t necessarily designed to be inspected. You do always run into some issues with that. Of course, for this one, we had to do vertical launches, etc., because there weren’t any traps installed, etc.

Russel:  That’s very interesting. We’ve talked about low flow. How low was the flow? What was the actual speed of the tool you’re running if it took 27 days to run the tool?

Denise:  The actual feed was 0.089 miles per hour. I don’t know about you, but 0.089 miles an hour doesn’t mean anything to me. I don’t drive my car that slow.

[laughter] 

I tend to cycle for the MS150 here in Texas. I don’t ride my bike that slow. It feels slow, but it’s not quite that slow. I started Googling all the things that we tend to think are slow. One of the things that I Googled was a turtle. People always think turtles are slow. They’re actually a good bit faster than that. I don’t remember the exact numbers off the top of my head, but actually, this turns out to be somewhere between the speed of your average garden slug and a turtle. Closer to the garden slug side of things.

Russel:  Oh my gosh.

Denise:  Very, very, very slow to get some feel around that.

Russel:  That is a great illustration. I read your paper. It had the numbers in there. All I remember is thinking that’s really slow, but that puts a whole new…about the speed of a garden slug, slightly faster.

Denise:  Yeah. Very slow.

Russel:  And much slower than a turtle. [laughter]

Denise:  Yeah.

Russel:  That’s just funny right there. That’s beyond crawling. That’s just really, really painfully slow. How did you even get a level of comfort that it was going to move and not get stuck?

Denise:  We did a good bit of testing to make sure of that. Our first issues were making sure that we could get some batteries and data recording to even see if that was going to be feasible to have the tool turned on and recording for that long.

Then the next issue was making sure that you didn’t get stuck in the line. Once you get stuck in the line, you don’t want speed excursions or whatever else happening when you hopefully start moving again. At that point, it was basically everything that you can do to reduce the friction on the tool and to make sure that you’re not bypassing anything.

We changed cups out with wheelbase carriers. Our tool fortunately is already a sled-based tool, which makes that a lower friction tool than a brush-based tool. We already have what’s called a no-touch design.

The ends of the mag bars have wheels on them, and so you actually travel along the pipeline with the wheels, and you have a very small space between the pipe wall and the magnet itself, which helps it be low friction to begin with.

I’m talking for making sure we didn’t have bypass, we went as far as to put little Teflon washers around every one of the bolts to seal the bolt holes to make sure we weren’t bypassing through that, because every bit of that pressure behind it, we needed to make sure we were capturing to propel the tool.

Russel:  At that low flow rate, I would assume there was likewise low pressure and a fairly low DP to make the tool move.

Denise:  Correct. The pressure was only about 100 psi.

Russel:  That’s a fairly risky operation, I would think. Had you all done anything like this before?

Denise:  Pipesurvey International particularly prides itself in these very, very difficult-to-run projects. They’re set up almost a custom job shop. Pretty much every tool that they run is largely customized for that particular application. They love a good challenge.

We’re the US subsidiary here. Of course, for the US market, we maintain a full fleet of standard tools on the shelf, but then we also have the opportunities to go back and leverage some of this customization and this history of our tools, of being able to customize things.

Russel:  That’s interesting. That’s a very different challenge than just the normal kind of I guess the 60, 80 percent of tool runs that are routine, as routine as a tool run can be. There’s no such thing as a routine tool run really.

Denise:  Yeah. It did help that this was a relatively large diameter line. It was a 20-inch line, basically 52 miles. Of course, with a 20-inch, because you have a larger area that that pressure is acting on, that does help. If this was a four-inch or six-inch line, I’m not sure that that would have been within the realm of physics.

Russel:  This is just an illustration of how my crazy, little mind works sometimes. I just realized that if you did 27 days to run a 52-mile long pipe that’s running slightly faster than a slug, that means a turtle could do 50 miles in about 25 days.

[laughter]

Denise:  Yeah, probably. I don’t know. We’ll have to get one and time it.

Russel:  Yeah, exactly. What were some of the other challenges just beyond the low flow and the low pressure?

Denise:  Like I said, the first thing that you have to deal with is the batteries. ILI tools, they’re just not designed to go that long. We had to add additional modules and optimize the battery packs, not the design of the actual battery, but the way that they were set up inside the tool.

With that additional battery, you had to start being concerned about safety for batteries. We were particularly worried about rapid discharge of that amount of battery. We did actually go through and do extensive testing, a 255-hour temperature cyclical test on the batteries to make sure that we weren’t going to have any issues in the application.

Aside from that, you start getting rid of everything that you possibly can that’s going to need batteries. One of the first decisions we made was to get rid of the IMU and replace it with a driver scope to orient the tool. IMUs tend to be very power hungry. That certainly helped.

Fortunately, because we were traveling so very slow, we were able to reduce our sampling frequency. We usually operate well over 1,000 Hz, and in this case, we lowered it down to around 20 Hz, giving us a sample distance of about 1.8 millimeters, even though it’s a very, very slow rate, because the tool is moving so very slowly.

Russel:  That’s interesting. I would assume by lowering that sample rate, that it lowered the battery draw to some degree.

Denise:  Yeah.

Russel:  But it also changed the amount of memory that you needed to put on the tool as well.

Denise:  Exactly.

Russel:  Did you end up needing more than standard memory for the tool or more than normal standard data storage?

Denise:  We did. We ended up using larger storage devices and we also had to actually go to multiple storage devices for the data.

Russel:  Interesting. I looked at the pictures that you shared with me and the paper that you wrote. Very interesting. I have never seen a vertically launched tool.

Denise:  Really?

Russel:  Yeah. I’m not an ILI guy, so I don’t know if that’s a normal kind of operation, or normal, not usual, or abnormal. What is the challenge of launching vertically versus typical with a pig trap?

Denise:  Obviously, it’s easier to do with a pig trap. The vertical launch is not unheard of. I don’t want to say common, but it’s not uncommon, especially offshore, where you tend not to have a lot of room to put things like pig traps on rigs. The main thing is making sure that you maintain control of your tool.

We tend to have a launching process that utilizes tubes. We install the tool into a tube, and then we use the tube to stabilize a multi-module tool and push that into the nominal, so we can drive out of the nominal with the trap. In this particular case that helped us as well, because we installed into the tube and then hung the tube vertically.

With a crane, you hold onto the tube with one line, and then the tool with the other, and then you’re able to push the tool down out of the tube right into the line, and close the doors and launch.

Russel:  That makes sense. It’s interesting. So many of these things in our world of pipelining is once somebody walks you through it, you go, oh, OK, that makes so much sense, but until you’ve actually seen it, it doesn’t come together. That actually makes sense, putting it into a tube.

You put the tool in the launcher and then swing the launcher and the tool both over the pipe that you can launch into, and then you launch.

Denise:  Yeah. It’s similar to that.

Russel:  I can certainly visualize that. That’s interesting. With this being a production line, I would assume that there were paraffin issues. What were the things you did prior to actually launching your inspection tool? Did you run cleaning pigs, or any of that type of thing? Did you have any kind of targets you were trying to achieve?

Denise:  We did. We knew that this line was going to have paraffin issues. It had been inspected about 10 years prior with an ultrasonic tool. In that particular application, they were not very successful. They did get data for the beginning of the line, but at the end of the line, they didn’t record any data, because of the extensive paraffin on the tool.

Of course, ultrasonic tools are much more sensitive to debris in the line, and especially if they’re gunked up with paraffin. It keeps those sound waves from reflecting off the pipe wall. That was one of the reasons that an MFL tool was chosen for this application, because it tends not to be as sensitive to debris.

In addition to that, we focused a lot on the MFL tool here, because it was the one that required most of the changes, but we did mechanical cleaning as well as caliper run and an MFL run for this line.

We evaluated the option of chemical cleaning, and along with our customer, we decided that wasn’t a very good application for this line, particularly because it was going into some storage tanks.

For the mechanical cleaning, we had to be very careful, because of course, if we were too mild, we would get a lot of data degradation. There was also concern that if we were too aggressive with our mechanical cleaning, that we would get these paraffin accumulations, these lumps of paraffin that as our very slow moving, low-pressure-driven tool started moving across, it would stop the tool.

Russel:  That’s one of the other things I’ve observed in the pictures you shared, is that when you pulled the tool, it looked like it had been a cleaning tool as well.

Denise:  That was a little bit concerning for us to be honest with you. We had a successful cleaning run. It did pull a lot of paraffin out, and we were pretty happy with that, but to be honest with you, a first look at the MFL tool itself, it was a little bit concerning.

Fortunately, when we got the data down, we found out that we had reached that fine line of cleaning where we hadn’t been too mild, we hadn’t been too aggressive, but we were still able to collect data.

Russel:  Denise, what would you say were the key things you learned from this project that you were maybe surprised by or didn’t anticipate?

Denise:  The main things or learning how to modify tools to operate in this type of extreme environment, particularly low-pressure and low-flow environment. When you just listen to it, 100 psi and 0.089 miles per hour. That’s really low pressure and really, really low flow.

Much like what I like about engineering, you start with a really big problem that sounds very daunting, but you start breaking it down into little pieces of batteries, cars, low friction, and sample rates, etc., etc. Then, all of a sudden, when all of those pieces come together, you’re able to solve something that sounded very daunting to begin with.

Russel:  I guess the biggest thing you learned is just what are the pieces of the puzzle and what are the things you can do to manage the pieces of the puzzle.

Denise:  Yeah.

Russel:  Interesting. This is, obviously, an unusual kind of run, at least so far as I know. Where do you think this type of application might exist outside of what you did in the North Sea?

Denise:  It’s interesting now, particularly with the PHMSA Mega Rule that was finally released last November. With that, there’s 425,000 additional miles of onshore gathering lines that are coming into regulation. Although it might not have been the intent, a lot of those lines end up being relatively low pressure and low flow lines.

Admittedly, a lot of those are a natural gas product instead of liquid product like this was, but all of the learnings on how you can function in those types of environments, particularly the low flow learnings, learning how you’re able to modify the tool to reduce the friction, as well as to prevent bypass, would all be applicable in those scenarios.

Russel:  The Mega Rule covers lines down to eight inches. Eight inches, that’s a pretty small tool. Do you see any challenges that would be beyond what you’ve already addressed that would come up as you scale the tool down?

Denise:  Of course, I think there’s always going to be some. In the case of those smaller tools, you’re going to end up with additional modules. With the additional modules, there’ll be more friction. Then you’ll have to have even more activity to reduce friction.

Then of course with the low pressure, you just have less surface area that is being acted on. It’s not necessarily just scaling it down and putting it in a line.

We are currently working on a 12-inch tool that’s in prototyping now, specifically to run in low-pressure task environments. We’re hoping that that’s going to run right around 80 to 100 psi, also very low pressure. Prototyping that out and doing flow testing with that currently, specifically for this application.

Russel:  I guess the other thing about natural gas too is you don’t have the paraffin issues. You might have water issues, but you don’t have paraffin issues. Just by their nature, they can have less friction just because of the nature of the operation.

Denise:  Yeah. You do unfortunately get the compressible natural gas, the compressible gas flow. You end up with some issues with some speed control – I’m sorry, not speed control, speed excursions that could occur in those products.

A lot of the learnings are applicable as a starting point, but there’s still a little bit more work to do.

Russel:  Do you think you’d be able to get something all the way down to eight inches?

Denise:  That’s the hope. We decided to start with 12-inch to do more feasibility studies, particularly switching to gas and switching to much smaller diameters. Then once that was available, we were going to start working our way down.

Russel:  What would you say that pipeline operators ought to know? What should they take away from this conversation? What do you think the general pipeline operator ought to know about this particular project and how it applies to them?

Denise:  I think the first thing, particularly being in the US market, the way that the US is run, it’s a little bit more of a production style, production being similar to mass production. In a lot of cases with companies, those have a tool fleet on the shelves, and either your line fits that tool fleet or sorry, we can’t help you.

I think one of the big things to take away is that there are still companies like us at Pipesurvey USA and Pipesurvey International that are interested and willing to attack some of these bigger projects, these things that aren’t usual and that won’t fit an off-the-shelf tool.

Russel:  That’s interesting. I think that’s exactly right. In the US, we tend to think of these guys that have these fleets, and it’s just a matter of picking a tool off the shelf and getting a schedule to run the tool, versus planning a project that’s outside of what’s common. Interesting.

Listen, this has been fun. I’ve certainly learned a lot. I think that the whole conversation about batteries, and battery life, and data capture, and all of that to me is really intriguing how you sat down and did all the math and figured all that out. That’s an intriguing conversation to me.

I think that has a lot of applications beyond just tools. It’s all over the place around automation and any kind of data collection these days, that whole how much data, how fast, for how much battery. That’s a pretty common conversation?

Denise:  Yeah.

Russel:  Anyways, any last comments or final takeaways before we wrap up?

Denise:  Just the fact that the run was successful. Looking at the final data, our odometers read 52.6 miles, a 52-mile line. That was pretty good. Max speed ended up being 0.167 miles an hour. Min speed was 0.022. Slower than a slug.

Ultimately, what matters is that we were able to keep the tool moving. If you look in the paper, there’s a really nice velocity time graph that shows that the tool was moving the entire time. It never stopped in the line.

Most importantly, we had less than 0.1 percent data loss through the entire run. It’s a very, very successful run.

Russel:  Yeah. It’s awesome. We will definitely take and get a copy of the paper, and we’ll link it up with the show notes. If anybody wants to read it, learn more, they can grab the paper and likewise see the pictures. Pictures don’t work on vocal podcasts, but we’ll link it up.

Denise:  Yeah, not so much.

Russel:  If you want to see pictures, you can go grab them.

[background music]

Russel:  I would encourage anybody who’s working or evaluating low pressure, low flow to take a look at this paper, because I think it’s really interesting.

Denise, I really appreciate you taking the time to be with us today, and look to have you back when you do some other interesting nobody-else-has-done-it-before ILI project.

Denise:  Thanks for having me. It was fun talking today.

Russel:  I hope you enjoyed this month’s episode of the Pipeline Technology Podcast and our conversation with Denise. Did you know it’s time to submit your nominations for the 2022 Pipeline and Gas Journal Awards? Simply go to the episode page at pipelinepodcastnetwork.com and click the link to submit.

If you would like to support this podcast, please leave us a review on  Apple Podcast, Google Play, or whatever smart device podcast application you use to listen. You can find instructions at pipelinepodcastnetwork.com.

If there’s a Pipeline & Gas Journal article where you’d like to hear from the author, please let me know either on the Contact Us page at pipelinepodcastnetwork.com or reach out to me on LinkedIn.

Thanks for listening. I’ll talk to you next month.

[music]

Transcription by CastingWords