In this episode of the Pipeline Technology Podcast, sponsored by Pipeline & Gas Journal, Russel Treat interviews John Strong from Polyguard to discuss the application of mesh-backed coatings as a solution for creating cathodic barriers in pipeline systems.

The conversation covers the importance of cathodic protection, the challenges posed by soil stress and aging pipeline coatings, and how Polyguard’s innovative mesh-backed coatings address these issues by providing durability and compatibility with various pipeline coatings, even under harsh conditions.

Using Mesh-backed Coatings to Create a Cathodic Barrier Show Notes, Links and Insider Terms

• John Strong is an experienced technical specialist with a focus on corrosion prevention and pipeline integrity. He currently serves as a Technical Field Specialist at Polyguard Products, Inc. Connect with John on LinkedIn.
  • Polyguard is an employee-owned manufacturer of protective coatings in a variety of markets, including the Pipeline Industry and Commercial Construction Industry.
• Cathode is the electrode from which a conventional current enters a polarized electrical device.
  • Cathodic Protection (CP) is a technique used to control the corrosion of a metal surface by making it the cathode of an electrochemical cell.
• Anode is an electrode through which the conventional current leaves into a polarized electrical device. 
• OD is the outside diameter of a pipeline.
• PHMSA sets federal pipeline safety regulations regarding the transport of product through pipelines, including requirements for corrosion control.
  • 49 CFR 195 focuses on pipeline safety regulations for the transport of hazardous liquids by pipeline.
    • 49 CFR 195.238 requires that no pipeline system component may be buried or submerged unless that component has an external protective coating.
    • 49 CFR 195.242 requires a cathodic protection must be installed for all buried or submerged facilities to mitigate corrosion. 
• Polyolefin is a type of polymer produced from a simple olefin as a monomer. For example, polyethylene is the polyolefin produced by polymerizing the olefin ethylene. 
• Polyethylene is a lightweight, durable thermoplastic with variable crystalline structure.
• Polypropylene is a thermoplastic made from a combination of propylene monomers.
• Field Joint is the point where two pipe sections are welded together.
• Corrosion is the deterioration of a steel pipeline that results from an electrochemical reaction with its immediate surroundings. 
• Composites are a blend of two or more dissimilar components to create a stronger, bonded material that supports a specific need, such as repairing damage in a pipeline. Composites are preferred in pipeline repair because of their strength, resistance to corrosion, versatility, and low coefficient of expansion.
• Epoxy: A type of polymer used as a matrix material in composites, known for its strong adhesive properties and resistance to environmental degradation.
• Polymer: A large molecule composed of repeating structural units, commonly used in creating plastics and composite materials.
• Carbon fiber: A high-strength, lightweight fiber used as a reinforcement material in composites, known for its stiffness and durability.
• Glass fiber: A strong, lightweight fiber used in composite materials, providing good tensile strength and resistance to environmental conditions.
• PE (Polyethylene): A common type of plastic used in piping, known for its flexibility and chemical resistance.
• PE100: A grade of polyethylene that can handle higher pressures, commonly used in industrial applications.
• Matrix: The continuous phase in a composite material that surrounds and supports the reinforcement fibers.
• Fatigue: The weakening of a material caused by repeatedly applied loads, a critical factor in pipeline design.
• Creep: The tendency of a material to deform permanently under the influence of mechanical stresses over time.
• Aging: The process of a material becoming more brittle over time due to environmental factors like oxygen exposure.
• Softening: The reduction in stiffness of a polymer when exposed to certain chemicals or temperatures.
• Accelerated temperature testing: A method of testing materials by exposing them to higher temperatures to predict their long-term performance.
• Ultrasonic inspection: A non-destructive testing technique using high-frequency sound waves to detect flaws or changes in material properties.
• Delamination: The separation of layers in a composite material, often caused by impacts 
• Weight coating: An additional layer added to a pipeline to increase its weight, ensuring it stays submerged underwater.

Using Mesh-backed Coatings to Create a Cathodic Barrier Full Episode Transcript

[background music]

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

Russel Treat: Welcome to the Pipeline Technology Podcast, Episode 49. In this episode, our guest is John Strong with Polyguard. We’re going to talk to John about using mesh-backed coatings to create a cathodic barrier. John, welcome to the Pipeline Technology Podcast.

John Strong: Thanks, Russel, good to see you.

Russel: If you would, tell me a little bit about yourself and how you ended up working with cathodic protection and barriers.

John: Russel, I’m John Strong. I work with Polyguard products. I’ve been with them for the past seven years. I started in this corrosion industry when I got out of school in 2008, and went from that great recession, where there wasn’t very many jobs. I just stumbled upon a pipeline job in South Texas. It’s one of those things, if you’re willing to live anywhere, this is the job for you.

[laughter]

John: I went down there, worked. I was lucky enough to have a really good boss who wanted me to be educated in, not just pipeline operating, but corrosion. He sent me to a lot of NACE courses and that jump-started my education and my direction in the industry.

Then eventually, I got highly focused on coatings. Going to South Texas out of school and working in the black dirt, being a corrosion tech for a few years, jump-started me for the rest of my career.

Russel: I think that’s awesome. I’ve never heard anybody say this, but I’m going to quote you frequently now as, “If you’re willing to work anywhere, pipeline business is a good place for you.”

John: [laughs]

Russel: That really sums it up quite nicely. I asked you to come on and talk a little bit about cathodic protection. Before we dig into what you guys do at Polyguard, maybe it’d be good…Most pipeliners are familiar with cathodic protection but maybe don’t really understand why it’s important and how is it typically done.

Why don’t we start out with that? Why is cathodic protection important? What is it doing? How do we typically approach it?

John: Really, cathodic protection is your last step in your fail-safe from preventing corrosion on your pipeline. Your coatings are always going to be your first barrier. CP is to step in when your coatings fail. That’s really your last instance to be able to protect your pipeline in a situation where it might become damaged.

Cathodic protection has been around for years and years. It’s morphed over the years to more computerized than it used to be, very analog. Essentially, it’s still the same premise. We’re sacrificing metal from a sacrificial structure and using that metal to force ions onto the pipeline.

We’re sacrificing ions from a piece of steel and using it to protect the pipeline that’s buried in the ground that you want to protect. It’s just kind of a circle of life. You’re stealing from that source and putting it onto your pipeline, is a real simple way to think about it.

Russel: I’m a sailor and I have a sailboat. That’s one of the big things you’re constantly checking, is your zincs because that’s your sacrificial metal so that all your propeller and your rod and everything else doesn’t corrode. The natural course of things for metal is for it to corrode. Our whole job is to keep metal in its manufactured state, not in its normal ore state.

John: The moment we take that metal ore and put energy into it, it wants to go right back to ore.

Russel: Exactly. Anybody that’s ever come across a piece of metal that was in their backyard and they dug it up, you know exactly what we’re talking about. You put it in the ground, doesn’t take very long. It doesn’t look like what it did when it went in the ground.

What are some of the typical challenges with cathodic protection? Like everything else, when you learn about it, what makes it hard?

John: The thing nowadays, Russel, there’s so many pipelines in the ground and systems. They’re all running different electricity on these pipelines. The systems can cause interference, especially at crossings.

A lot of pipeline companies, they don’t even know those pipelines cross. That’s something that hasn’t even been surveyed, or it was something that happened 50 years ago, before the people that are working nowadays were even around.

Your cathodic protection interference is a big issue nowadays with the high AC transmission lines also running on pipeline right-of-ways because that was an easy place to put them because it was already cleared out. They had a straight shot to run right on the pipeline right-of-way. You can induce AC current on your pipeline, it’s going to mess with your cathodic protection system.

Then, one of the main things is, as our pipelines are getting older and their coatings are aging, the coatings have a tendency to shield the cathodic protection if it’s failed. For instance, lots of pipelines were coated with coal tar.

When you dig up a pipeline that was put in the ground from the ’20s to the ’50s, it’s almost guaranteed to be a coal tar pipe. That coal tar, as it sees soil stress, will crack normally. Normally, it’s right at 12 o’clock. It’ll just be a fracture.

What happens is your groundwater or your electrolyte goes into that crack and it’ll settle along the inside of the coating and your cathodic protection has no way to go through the coal tar, unless it’s so deteriorated that it’s not acting as a coating anymore.

Normally, it will be enough of a coating where it will block your cathodic protection from reaching the pieces of the pipe that it needs to protect.

Russel: Talk a little bit about the kinds of coatings that are out there and maybe a little bit about their strengths and weaknesses. One of the things I’ve heard about coal tar is that it’s still a pretty dadgum good coating.

There’s still a lot of coal tar out there. There’s a lot of pipes and you uncover them. They’ve been in the ground a long time and had coal tar. You go, “Well, this stuff works pretty good.”

John: It was a great coating and it’s like anything else. Sometimes it was put on better in some instances than others. Shrink sleeves wears a huge coating. It’s still pretty big overseas. It was one of those things, it’s only as good as the guys putting it on. It seemed like they had more failures from applications than other types of coatings.

Another really popular one was polyethylene tape, like almost what you would get at Home Depot for roofing jobs, real thick electrical tape. That stuff, when you pulled it, it had a lot of elongation, so when you’d pull it and stretch it, it would get skinny in the middle. That’s a very good indication.

If you’re pulling and stretching it with your hand and the product doesn’t need a release liner because it doesn’t stick to itself, it’s not going to stick to the pipe. People ran into a lot of failures with polyethylene tape. That tape essentially gave the entire tape industry a bad name, just a bad reputation.

Another coating that’s been around forever and performs pretty well is your wax tapes, your petrolatum tapes. That’s essentially a field-applied coating. You can hand apply that with a primer normally and then you wrap it. It’s a moisture barrier and it’s been around forever.

Any pipeliner you talk to has probably touched it and then had to take entire bath before they got back in their truck. Stuff’s just messy.

Russel: That’s one of the things that’s thematic, in my mind, about all of these coatings, is many of them have field application. Nowadays, it’s not uncommon to buy your pipe strings with coating already applied, but if you do that, you still have to weld them and you still got to manually apply the coating over the welds.

Anything that you do manually in the ditch is going to have more inconsistency in its implementation than something that’s done in a manufacturing facility. It all inherently is going to have some level of fault in it.

John: The FBE, like the pre-coated pipeline sticks that you’re talking about, even the guys that go out in the field and use the spray ring and FBE, apply it in the field, they run into issues. You have to have that induction heat perfect all the way around the pipe for the powder to form correctly to the pipeline.

Once you get into the field, it’s just a different animal. You want your coating to be a little bit forgiving and not…If the guys are applying it and make one misstep, it’s going to fail.

Russel: It’s really interesting. Because I’ve been doing this podcast now for a while, I end up having these conversations and I have a notional understanding about a lot of things, but I’m very clear I don’t have a thorough understanding about very many things. I know the things I know well and CP and coatings is not one of them.

The way I understand this is that the coating works in conjunction with the cathodic protection system. By putting the coating on, it creates a barrier between moisture and the soil and other things that will cause those electrochemical interactions that will accelerate metal loss.

Then for those places where I have imperfections in the coating, I’m putting on CP to further protect the pipe. That’s a fairly good explanation, right?

John: Yes. Your imperfections need to be something that most likely exposes the steel. If it’s an imperfection, say with like a polyethylene tape where, say a chunk of dirt got under it or something as you were wrapping it or water, it’s not going to have a path to get to the steel. That water is just going to sit there and corrode your pipe.

Russel: That’s the thing about any coating. The coating needs to be bound to the pipe. Any gaps between the pipe and the coating are problematic, for all kinds of reasons, right?

John: Yes.

Russel: It causes problems with all the inspection tools as well. It’s pretty interesting. A sidebar conversation for what I asked you to come on and talk about, but just the idea that we have the ability to run robots through these pipelines and find that kind of stuff is wicked, if you think about it. It’s pretty wild.

John: They have all kinds of tools that can assess your entire CP system even. It’s crazy how that they can have a reference cell give them information from the outside of the pipe that when they’re running the tool on the inside is crazy. [laughs]

Russel: That’s one of those things that you have to know a lot about it to understand it. I wanted to talk to you about some of the issues. We’ve talked about water, we’ve talked about application, but I think probably the other thing that we haven’t talked about is pipeline movement, because anytime you have a coating, the coating is something different than the steel.

As that steel moves, it’s going to have a tendency to want to work loose from the steel. That’s a reasonable assumption, right?

John: Yeah. It’s definitely something that you need to take into account. Your shrink sleeves were one of the original ones that soil stress just killed, soil stress or pipeline movement. I’ve seen instances where they dug up the pipe and the girth weld was bare and the shrink sleeve was three feet away from the girth weld. It just slid like a ring around the pipe, just slid down the pipe.

Russel: Wow.

John: In Alaska, when I worked for Tesoro, if we dug up any of that Trans-Alaskan Pipeline, we would expose it for a few days and some of those Alaska days would have a 70-degree temperature swing. You could see the pipe straight and in the afternoon, it would be crooked.

The steel would definitely expand and if your coating is not meant for that much flexibility to happen, it’s going to fracture. Your two-part liquid epoxies, that’s a field coating that, if you have a lot of expansion and contraction, it’s probably going to fracture.

The failure mechanism of that epoxy isn’t to shield the CP. If it fractures and breaks off, it’s normally just going to leave a bare piece of steel for the CP to protect then, so you’re in a good situation there.

If you’re in a situation where a shrink sleeve just slid down your pipe, then that’s just extra insulation that’s just sitting there. You might as well have wrapped it in a garbage bag or something. With our mesh-backed coatings, the mesh doesn’t stretch very much, but it does have slight elongation. You can pull it.

Russel: That’s a great segue. Talk to me a little bit about what you guys do at Polyguard and what is a woven fiber play into this idea about coatings?

John: The guys that created these woven mesh-backed coatings, they saw something in the industry that was happening and there’s a lot of coating failures due to soil stress. It was all your polyethylene tapes and your shrink sleeves. Everything was sagging. Once you buried it and the soil stress pushed on the coating, it just elongated, sagged, and bagged at the bottom.

They figured that if they attach this woven mesh to the outside of the actual corrosion coating, it would give it these properties where it just wouldn’t stretch. You think about your Kevlar bulletproof vests and all your ballistics fibers, all of those things are just woven material. That weave is what really gives it a strength and doesn’t allow anything to stretch or break.

That woven fabric is also not a solid piece of plastic. It’s made out of polypropylene, but it’s all just fibers woven together. If you had a sheet of it, you could just hold it up to the light and see right through it.

That is what was the aha moment. It gave us all the strength we needed to be buried in the soil and resist soil stress. Also, if there’s damage to the outside of the coating or even, say a rock presses against the coating, there’s a direct pathway for the cathodic protection to just go through the outside of the coating to the steel.

That was the problem everyone else was having with the tapes. The film on the outside layer was just a solid film. If there was any damage under it or it came unadhered to the pipe, it just blocked the CP current to the pipe.

Russel: Interesting. I want to understand that mechanism a little better. Let’s talk about soil stress first. I’m trying to visualize what that means. Basically, once you bury the pipe, that pipe is trying to move because of bends or normal ground movement or changes in temperature.

The pipe is trying to move and at the same time, the soil is trying to move, but they’re not trying to move in the same way.

John: The worst soil stress is wet and dry cycles. If you go down to South Texas, where it’s been dry for months and then you get a bunch of rain, it’s that cycling back and forth, oh, man, it’s bad. It’s really hard on coatings.

Russel: Being a structural engineer, I’m trying to visualize what that’s doing from a stress and strain standpoint. What I do know is these clay soils that are very water-rich, as they dry up, they shrink.

John: Yes.

Russel: You know that around your foundation and such. You know that your house settles as that ground…Then when it gets wet, it’s like a sponge. It shrinks. Then it expands and then it shrinks and then it expands. If I’ve got a pipeline running through that, then that’s creating pressure…

John: It’s all that movement.

Russel: …or is it longitudinal strain between the pipe? It’s like trying to rub the coating off the pipe.

John: Yes. You can see it. When you dig a pipe up and look at the coating that’s had soil stress against it, it looks like someone’s just tried to press it off. It’s normally looks like it’s being pushed from the top to the bottom. It looks like everything’s just getting squeezed down to the bottom.

Russel: Why is that? Why is that top to bottom versus along the side?

John: I’m not 100…Nothing ever looks like it’s getting folded across the side. It’s always top to bottom, that force.

Russel: I don’t know enough about the soil mechanics to know. [sighs]

John: [laughs]

Russel: Man, I’m thinking about the professor I had in university where I took geotechnical. Guy was freaking brilliant. Taught me things I didn’t think I learned or didn’t know that I needed. Anyways. That’s a whole long sidebar conversation. It’s interesting. Basically, it’s like the soil is constantly pressing down on the side of the pipe?

John: Yes.

Russel: I guess that makes sense because that soil is loading up. As it gets wet, it gets heavier. If it gets dry, it gets lighter. As it gets dry, it comes away from the pipe and then it gets wet and gets heavy and…I guess that makes sense.

John: It’s cyclical, that wetting, drying. That’s…

Russel: It’s a big deal.

[crosstalk]

John: …a lot of soil stress.

Russel: I know, around my house, there was two or three inches of movement every wet-dry cycle.

John: Wow.

Russel: It’s a lot. That’s interesting. Woven fiber, how is it applied? Do I add it to the coating? Is it an addition to the coating, or is the coating and the fiber one thing together? How does that work?

John: It’s one thing together. It already comes pre-packaged. It’s on a roll. The fiber is attached directly to our coating system. It has a release liner. As you’re applying it, you’re pulling the release liner off and wrapping it on the coating.

This stuff, we show people and we tell people that every time we train them, it takes a lot of tension to apply this coating correctly, that you want to press it as hard as you possibly can. You can give a guy a roll, the biggest guy on the job site, and tell him to go for it, he can’t pull it apart. No amount of human strength…

[laughter]

John: …is going to be able to make this coating fail. We use a manual machine also that presets the tension, uses kind of like a brake system. You just run it down the pipe and it sets your overlap for you. Everything looks really perfect. You want to pull it as…

Russel: Are you using that as a primary coating, or are you using it as a means of remediation when you’re doing digs and you’re repairing things?

John: It’s both. We’ve coated many, many girth welds on new construction with RD-6, that mesh-backed coating. It’s very common. I guess depending on level of surface preparation, the guys in the field can do…

I know, in West Texas, when the wind’s blowing 50 miles an hour every day, they can’t do two-part epoxy. That’s a real common field coating because it just gets caked with dirt. When they go to holiday detect it, it’s just filled with dirt.

Our coating system, it doesn’t take any time to cure, so you can prime it and wrap it immediately. You’re taking away that instance for the dirt to just get blown and contaminate the surface. It makes a lot of sense on some projects to use that.

Russel: Interesting. I get how the fabric creates an extra layer of protection and helps hold the coating up against the pipe. That’s easy for me to visualize and understand. I get that it’s quick to apply, which also has some real benefits. What are some of the other benefits of this kind of approach or this kind of application?

John: This coating, it’s compatible with any other type of coating. That’s not always the case for everything else you see in the field. You can put it over anything. Your surface preparation, as long as your steel is clean, there’s not a bunch of dirt or just caked-on rust, it’s going to stick to it. Doesn’t require the clean, near-white blast that other coatings require.

This, it goes on fast. What the guys out in the field really like, they don’t have to wait four hours when the job’s done and just sit and stare at the pipe. They can wrap the pipe and then holiday detect it, and you can bury it. Once the job’s done, it’s pretty much done. You don’t have to sit there and cure or wait for the coating to harden up.

That’s something that, especially if you’re working in a right-of-way that’s a street or, say something that’s guarded by Homeland Security, they don’t want you there once it’s dark. We’ve ran into that before, so you got to leave the hole open, exposed with a coating that’s curing. God knows what is happening once you leave. We run into…

Also, in the winter, if you’re using some liquid coatings and say you had to leave the hole, come back the next day, if it got below freezing, you got to take the coating off because the frost will get embedded in the liquid coating and it’ll never cure. You just have to take it off and start over. There are definite benefits to using the mesh-backed coating.

Russel: How does it compare price-wise to the other alternatives?

John: Honestly, it’s probably a little more expensive if you priced it out per weld, but your time…It’s probably a quarter of the time to do the application. If you factored in your labor, you’re way ahead, but just the material cost, it’s more. Not a lot more, but it is more.

Russel: One of the things that has come up for me a lot as I’ve had conversations about pipeline repair in particular, where they’re talking about composite repairs and sleeves and various things is that, oftentimes the cost of repair is not the materials’ cost. It’s not even the labor cost. This would be different here, but it’s the cost of the impact on production.

If I have to derate a pipe and slow production down to expose it to mitigate risk, then the less time I have that hole open, the less cost I have. If that’s not an issue, then, again, the less time the hole is open, the less cost I have. It’s expensive to expose pipe and it’s expensive to leave it exposed.

John: Yes. We’re a small line item on that project list, when it comes to materials, at the end of the day. [laughs]

Russel: That’s right. Of course, with everything else, there’s a whole bunch of, you got to know how to use it. You got to have people know how to apply it, how to evaluate it, all those kind of things.

John, I’ve just asked you a wrap-up question, is there anything else you want to add to our conversation you think pipeliners ought to know about this approach to putting coating in place?

John: I think we’ve hit most of the big parts, Russel. I just know, in the past, there’s been lots of confusion regarding shielding, non-shielding, why coatings act a certain way when they fail. I think Polyguard, we’ve tried, the last few years, to clear it up, just clear the air. The coating doesn’t shield because it has a woven fabric. That is it.

It doesn’t have a solid film on the outside and there’s no magic after that. [laughs] There’s nothing this coating does different than any other to protect the structure. It just has a different backing that makes it perform better than others.

Russel: It’s really more about life of the application once it’s applied and its ability to deal with all the typical kinds of adverse effects that would impact coatings.

John: Yes.

Russel: Cool.

[background music]

Russel: Look, I appreciate your time, John. I’ve certainly learned a thing or two about coatings and all of that, so this is good. I appreciate your time.

John: All right. Thank you, Russel. I appreciate it also.

Russel: I hope you enjoyed this month’s episode of the Pipeline Technology Podcast and our conversation with John. If you’d like to support this podcast, please leave us a review. You can do that on Apple Podcasts, Google Play, wherever you happen 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.