This week’s Pipeliners Podcast episode features returning guest “Mr. Corrosion” Bob Franco of Franco Corrosion Consulting providing an introduction to pipeline coatings, specifically how to control external corrosion with coatings.

In this episode, you will learn about what to consider when looking at different coatings to help prevent corrosion in pipelines, the different kinds of coatings that are available, and the history of coatings within the pipeline industry.

Introduction to Pipeline Corrosion: Show Notes, Links, and Insider Terms

• Bob Franco is the president of Franco Corrosion Consulting. Bob was a Sr. Materials & Corrosion Consultant for 44 years at ExxonMobil. Connect with Bob on LinkedIn or email hime at mr.corrosion@yahoo.com.
  • Franco Corrosion Consulting offers consulting in corrosion mitigation, corrosion threat assessments, risk-based inspection planning, materials selection for upstream oil and gas production operations and new developments.
  • Listen to Bob Franco’s previous Pipeliners Podcast appearance in Episode #121 – An Introduction to Pipeline Corrosion.
  • NACE Book: Order “Corrosion Control in Petroleum Production, 3rd Edition” written by Bob Franco and Timothy Bieri and published by NACE.
• NACE is an international organization dedicated to protecting people, assets, and the environment from the adverse effects of corrosion.
• Corrosion is the deterioration of a steel pipeline that results from an electrochemical reaction with its immediate surroundings. 
• 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. 
• Trans Alaskan Pipeline is an oil transportation system spanning Alaska, including the trans-Alaska crude-oil pipeline, 11 pump stations, several hundred miles of feeder pipelines, and the Valdez Marine Terminal.
• Fusion Bond Epoxy (FBE) is an environmentally-safe thermosetting coating that is sprayed onto the pipe surface after it has been cleaned and heated to over 450ºF.
• 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.

Podcast Note from Bob Franco: Six Essential Factors for a Good Pipeline Coating Project

Choosing the right coating system for the pipe body and field joints is not the only component of a good pipeline coating project. Here are several important considerations.

1. Select the correct coating for the pipe body and girth welds.

2. Prepare the pipe and girth weld surfaces to ensure good adhesion (Surface Preparation). Typically, the minimum surface preparation standard for the oil and gas pipeline body is SP 10 Near-White Blast Cleaning.

3. Apply the coating to specification. All coatings for the body of the pipeline are shop-applied by automation. The same goes for field-applied joint coatings, except when rough terrain or close quarters prevents the use of automatic units and manual spray coating must be applied.

4. Thoroughly inspect during all phases of the project, including surface preparation, coating application, and the finished coating including coating film thickness.

5. Prevent damage to the coating after the pipe leaves the coating mill and is transported to the job site and installed (in the ditch or the offshore lay barge). Wait until the coating is cured before burying it or installing it in water.

6. Maintain the coating as necessary during its service life. CP surveys and inline inspections may disclose areas where coatings have been damaged and should be repaired if cathodic protection cannot be adjusted to provide adequate protection.

Introduction to Pipeline Corrosion: Full Episode Transcript

Russel Treat:  Welcome to the Pipeliners Podcast, episode 155, sponsored by Gas Certification Institute, providing training and standard operating procedures for custody transfer measurement professionals, now offering online interactive and instructor-led training. Find out more about GCI at gascertification.com.

[background music]

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

Russel:  Thanks for listening to the Pipeliners Podcast. I appreciate you taking the time. To show the appreciation, we give away a customized YETI tumbler to one listener every episode. This week, our winner is Dustin Brisset with Duke Energy. Congratulations, Dustin, your YETI is on its way. To learn how you can win this signature prize pack, stick around until the end of the episode.

This week, Bob Franco returns. Bob, known to his friends, and I count myself as one of them, as Mr. Corrosion, is going to talk to us about controlling external corrosion by using coatings. Bob, welcome back to the Pipeliners Podcast.

Bob Franco:  Russel, it’s a pleasure to be back for part two.

Russel:  [laughs] It’s good to have you, Bob. Maybe for the listeners that hadn’t heard part one, you could do a quick introduction. Tell us about yourself and how you got into corrosion protection.

Bob:  Sure. My name is Bob Franco. I’ve been involved with corrosion control activities for 50 years, and with pipelines in particular for 34 years. I got involved with corrosion because my degrees are in metallurgical engineering, and my first job got me involved with corrosion.

I’m the author of an upcoming book on corrosion control and petroleum production. It’s the third edition of this book. It’s printed, and it is now available for purchase from NACE.

Russel:  You can literally say that you wrote the book on corrosion protection.

Bob:  Yeah, you could say that because there’s 11 chapters in this book, and I wrote 7 of them. I have a co-author who happens to be the current president of NACE. Yeah, at least I wrote 7 out of 11 [laughs] on the book of corrosion.

Russel:  There you go, man. For the listeners, I should also explain that Bob and I worked together on a specialized consulting team. I’m the leak detection subject matter expert, and Bob is the corrosion subject matter expert. I have been baffled and bewildered, which is why I asked him to come on the podcast so I could get educated. [laughs]

Bob, why don’t we do this. Why don’t we start out with a quick review of what we talked about last time and the fundamentals of corrosion protection?

Bob:  In the first podcast, I described the basics of corrosion of carbon and low alloy steel pipelines. A quick run through of those highlights. First of all, corrosion is not just a chemical reaction, but it involves the creation of a battery cell called an electrochemical cell.

I’ll explain that because corrosion requires four parts of this cell to function. Any one of these cell parts could be eliminated, and then corrosion will cease.

First, we need an anode, and from the pipeline perspective, that’s the part of the pipeline that corrodes. Second, we need a cathode, which is the part of the pipeline that does not corrode, but it’s vital for the corrosion to continue because it exchanges ions and electricity with the anode.

Then there’s a metallic path between anode and cathode. That’s the pipeline itself because parts of the pipeline are anodes, little micro anodes, and parts are little micro cathodes. They communicate through the pipeline steel to each other.

Then we need an electrolyte, which is water. Without that, we don’t have corrosion. Water has ions dissolved in it. These are positive and negatively charged particles dissolved in the water that migrate towards the anode or the cathode depending on their charge.

For example, negative ions such as chloride migrate towards the anode. Positive ions such as iron that dissolved into the water — they migrate to the cathode. Plus charges are migrating to the negative side and vice versa.

The typical electrolyte, as I said, is water, but from a pipeline perspective, that’s going to be wet soil for a buried pipeline and a body of water for a submerged pipeline.

In the first podcast, I briefly described corrosion prevention, and there are two corrosion barriers that are used in combination to control external corrosion occurring on the OD of the pipeline. They are external coatings and external cathodic protection.

These barriers are required by regulations. For example, in the U.S., we have the 49 Code of Federal Regulation, paragraph 195.238, which requires that no pipeline system component may be buried or submerged unless that component has an external protective coating.

We have another paragraph, 49 Code of Federal Regulations 195.242, which requires a cathodic protection must be installed for all buried or submerged facilities to mitigate corrosion. These regulations cover pipelines like interstate pipelines and pipelines that are covered by these federal regulations.

Russel:  I would assume there’s equivalent regulations for 192 as well, right?

Bob:  192, I think…

Russel:  That’d be the gas side of the pipeline.

Bob:  Yeah, oh, sure. I’m glad you mentioned that, Russel, because I was concentrating more on the liquids there, but absolutely, it’s the same.

Russel:  Yeah, right. I know you’ve spent most of your career in liquid pipelining, so I just want the gas guys to get their fair share. They’re covered by the rules as well.

Bob:  [laughs] I’ve done work with wet gas pipelines, not dry gas transmission lines. Now, of course, I don’t want to leave the viewer thinking that external corrosion — or the listener, rather — external corrosion is the only problem, because we do have internal corrosion problems depending on what’s being transported inside the pipeline.

For internal corrosion, we use corrosion inhibitors, and we have pipeline maintenance pigging to remove water and internal debris that causes corrosion. In some less common circumstances, internal coatings may be applied. My experience is that they’re not used nearly as frequently as the external coatings.

Russel:  That could be problematic for all kinds of reasons.

Bob:  Oh, yeah. Fabricating the pipeline is the main reason. You’re going to be welding joints together, and you’ll burn through the coating that you applied, which means that you’ll have to do the coating after you’ve constructed the pipeline, which isn’t the best way of getting a great coating job.

Russel:  That actually tees up what I asked you to come on to talk about this time, which is coatings.

Bob:  Exactly.

Russel:  Again, like last time, where I was getting educated, I’m going to get educated. I have only a notional idea about what a coating is. Maybe a way to tee this off is to ask what are the kinds of things you’re thinking about when you’re looking at coatings.

Bob:  You want to know if the pipeline’s buried or submersed. You want to know what the temperature inside the pipeline is, so how hot the outside can get. You want to think about how the coating is going to be applied, particularly most of that is on the pipeline segments – they get delivered to the job site, and they’re already coated.

It’s the girth welds, the field welding, that needs to get coated on the job site. That’s a very important consideration, because the user has to address coating the pipeline body and the field girth welds.

Choosing the wrong girth weld coating creates a weak link in the chain. It results in shortened pipeline service life, and frankly, a lot of times, the failures occur at girth weld coatings.

Russel:  One of the things I certainly remember from our last conversation on this topic is that where you have a problem with the coating is where you’re likely to have a problem with metal loss due to corrosion.

Bob:  Yes, because again, it’s a combination of coating and cathodic protection. When they work in tandem very well, the amount of current required from cathodic protection is minimal. The cathodic protection only has to protect small areas where the coating damage is.

You run into trouble when you have massive coating failure along the length of the pipeline, and your design for your cathodic protection system was not meant to throw current onto that amount of bare steel on that pipeline.

It was designed to only cover a certain extent of coating damage. A few percent, up to maybe 10 percent of bare metal. Beyond that, your pipeline wasn’t designed to provide that much CP  current. Otherwise, you need much more current capacity than we typically build in.

Now, the other considerations that you have, besides whether your pipeline is below ground, above ground, and what you’re transporting is, very importantly — and I mentioned it already — is temperature, because the coatings that we’re going to talk about have very different temperature capabilities.

If you get into a situation where the temperature exceeds the coating’s capabilities, you get extensive coating failure, and then you have real external corrosion problems.

Russel:  Interesting. What are the temperature ranges that you’ve seen? Obviously, you’ve got extreme cold if you’re in the Arctic. Then I guess you have extreme heat if you’re in the Sahara or something like that.

Are there other situations where you’re moving a fluid, and the fluid temperature would impact that?

Bob:  Oh, very much so. You can get a produced crude. Crudes can be warm…You have different considerations. For example, let’s take Alaska. When crude goes through the Trans Alaskan Pipeline, the crude will congeal in the cold temperature, even though the pipeline is insulated.

They have to have a certain temperature for free-flowing crude. You could get into temperatures that are 140 Fahrenheit or so. Then, when you produce the oil or gas — that if you’re transporting those kinds of products — gas, for example, can come downstream of a compressor station that really heats it up. Crude can come out of the ground hot, so that also, can be hot. You can get into some real temperatures that’ll even reach 180, 220 degrees Fahrenheit.

Russel:  What’s the bigger problem with coatings? Is it heat or is it cold? Or are they just different problems?

Bob:  It’s mostly heat, but cold, you have to consider thermal expansion of the pipeline, too, because particularly for a buried pipeline, as the pipeline shrinks and expands from different temperatures — particularly larger delta Ts — it’s going to try to move in the soil, and it’s constrained.

You end up shearing the coating. You can have a shear failure in the coating from delta T. If you started off, let’s say you built the pipeline in a very cold situation, and then you operate it later in a hot situation, there’s going to be a pretty extensive thermal expansion going on that the coating will have to withstand.  

Russel:  Again, as you talk through this, it makes sense, and I can visualize it, but it’s something I would have never thought about before this conversation is just the thermal expansion and the movement of the pipeline could cause the pipeline to separate from the coating. It’s interesting, actually.

Bob:  Actually, it causes the coating to separate from the pipeline.

Russel:  Well, yeah.

Bob:  [laughs] Yeah.

Russel:  What are some kinds of coatings? Maybe talk a little bit about the history first. I love to hear the history of this stuff. You’ve been doing this for 50 years. You’ve got a lot of the history in your own personal experience.

Bob:  Yeah, I do, and these coatings, this all precedes my life. It goes on beyond that, too. It really started in the 1920s, because prior to that, there was no…even throughout World War II.. there were no requirements to have pipeline coatings on buried pipelines.

There were no standards. There weren’t any guidelines. Starting with the 1940s, coal tar enamel became the standard. That consisted of applying a hot coal tar pitch, with reinforcement layers, which is a felt. At the time earlier, it used to be asbestos fibers. Now, that’s been replaced by glass fibers.

There’s two layers of reinforcement. As a result, this coal tar enamel was a very thick coating. It’s like 3/16ths to a quarter of an inch thick. It’s a glasslike, very hard coating. In fact, the job that you mentioned we were working on together, some of their pipelines that go submerged underwater have this coating on them.

They’ve been in service for 65 years, and there’s history of that coal tar enamel coating even in other water reclamation products at the Department of the Interior and all that at 80 years life. Fantastic life.

Russel:  That’s just amazing.

Bob:  It has its cons as well. First of all, it has a very modest temperature capability, which limits…You can’t really use it in these hot applications I just described. Also, it’s not a CP friendly, or cathodic protection friendly, coating.

That is, should the coating fail, it fails in a bad way that prevents the cathodic protection from working underneath the failed area. You end up with an extensive corrosion that you may not recognize right away until failure.

Russel:  These old construction pictures, where you see the guys wrapping the pipeline and painting the pipeline with the goo, that was coal tar epoxy?

Bob:  A wrapping, we’re going to cover tapes in this discussion. What you see being wrapped around the pipeline is what we call, it’s a tape coating, and it has a mastic kind of sticky part of it that adheres to the pipeline once the pipeline’s been prepared for coating.

Then it has an outer layer of a plastic film like a polyethylene tape. That’s when you see them with rolls, and they’re going around the pipeline.

Russel:  I’m referring to these old black and white photos I see of guys working in the ditch trying to put the pipeline in the ditch. That’s more what I’m referring to.

Bob:  Well, you could do these tape wraps in the ditch as well. Those are not the favored coatings today, and again, there’s two reasons for that. They don’t have high-temperature capabilities, and we’ve had pipeline failures because of coating failures. They’re not that CP-friendly. A coating failure prevents the cathodic protection from sending current beneath the failed coating.

Russel:  Based on those old photographs I’ve seen, they didn’t look like they were installation-friendly, either.

Bob:  [laughs] No, you got to get in the ditch to tape wrap a field joint. It’s applied in the field. You got to get in there. You can imagine the six o’clock position of a buried pipe. You go to have enough clearance to get in underneath to see what you’re doing and allow tension on the tape roll..

Otherwise you’re going to have wrinkled tape, and wrinkling is bad, because when the thermal expansion occurs, wrinkles act as a site where the tape rips off or breaks apart.

Russel:  Yeah. I’ve had another guest on the podcast who loves to talk about history. He’s a third-generation pipeliner. His grandfather ran a mule team up in the Northeast to string pipe. He talks about how they paid the guys and what the process was of getting the coating on the pipe before it went in the ditch. It was basically, work as fast as you can and don’t let the pipe lay on you.

[laughter]

Bob:  Not exactly Code of Federal Regulation, was it? [laughs]

Russel:  No. We would no more do something like that in this day and age than the man in the moon. It’s an indication of how far we’ve come.

Bob:  After many years, coal tar enamel, because of its toxicity with hot coal tar vapors — it got replaced with coal tar epoxy. You still can get coal tar epoxy today, but we’ve gone even beyond that, and we’ve gone into two coatings that are in the more modern era.

One is, we’ll call fusion bond epoxy, or abbreviated FBE. The other one is three-layer polyolefin systems. Polyolefins are polyethylene or polypropylene.

I’m going to only talk about polypropylene today because that’s the higher temperature capable coating of the two. Polyethylene is much lower temperature capable. In the history part, the first part, and I lived through this history, in the 1970s, fusion bond epoxy started coming up big and being used in pipelines.

That’s when that technology was really developed and improved. The three-layer polyolefin or polypropylene is a much more recent coating system which is more like, I would say, the last 20 years, 15 to 20 years. If you allow me, unless you have any questions, I’ll go on to fusion bond epoxy.

Russel:  Yeah, let’s dive in.

Bob:  You may have seen fusion bond epoxy applied to pipe that’s being laid. If it looked green, for example, that’s a very typical fusion bond epoxy color. You start with these coatings. They start with a hundred percent solids epoxy in a powder.

Most of the time — you’ve all made epoxy at home with glue, and you know that you need the resin and the catalyst or the hardener. You have to mix them together. In fusion bond epoxy, the powder has these things in it. In the shop, you electrostatically spray this powder onto a hot abrasively blasted pipeline. You got to get the pipeline up pretty hot, like 430 to 450 degrees Fahrenheit.

What that does is it melts that powder and it forms a liquid. The beauty of fusion bond epoxy is it quickly solidifies because you’ve got the epoxy resin and the hardener together, so you get cross-linking going on.

The pipeline’s hot. Well, these chemical reactions occur quickly, so within under a minute, FBE is a solid epoxy plastic. Epoxy is a special kind of plastic called a thermosetting plastic. That is, once you get it cured and you heat it later, it’s not going to return back to a liquid or something that flows. It’s just going to char.

You can never return it back to the way it started, which distinguishes it from something like polyethylene, which does go back and forth between a liquid, solid, and you could keep reusing it and reshaping it and all that.

Epoxy doesn’t do that. Epoxy is applied in a single layer, which is usually 14 to 20 mils thick, — a mil is a thousandth of an inch. You could also do a dual-layer epoxy. You run the pipe through again. It’s the same epoxy you applied earlier. It’s approximately twice the thickness.

The reason why you do the double one is, number one, the two epoxy layers are totally combined as one. Number two, you get a higher level of performance and a higher temperature capability than the single layer.

Epoxy came in, like I said, starting in the ’70s, and probably there’s even earlier history of it. I became aware of it in the ’70s. It’s the most popular pipeline coating system today. It gives you excellent chemical resistance, and chemicals, of course, include water. If the line is under a body of water, it resists that body of water as well.

Also, during the corrosion reaction between anode and cathode and all this, you build up chemical species — as I said, species migrate between the positive anode and the negative cathode. Ions are transferring. You build up negatively charged hydroxide ions, OH ions, at the cathode. Hydroxide eats through a lot of coatings, but not fusion bond epoxy. Fusion bond epoxy resists that.

Cathodic protection increases the amount of hydroxide ions you form. It’s part of the chemical reaction and the electrochemical reaction I described earlier in the first podcast. You cannot stop that from occurring. The coating has to resist soil, has to resist water, has to resist alkali hydroxide.

Russel:  This coating, it’s actually compatible with and works effectively with the cathodic protection system.

Bob:  It is absolutely more protective, not because of the hydroxide. It resists the hydroxide. It’s the two together – coating + CP – that protect the pipeline.

I could give you a perfect fusion bond epoxy coating leaving my pipe mill, and then it has to get on trucks and trains and whatever to get to some distribution center. Then it gets brought to the job site. Then it gets brought to the field where it’s being put in the ditch.

Over the course of all that, it gets some abrasion damage. It gets chips, a few chips here and there. Most companies have a standard where they say they’ll repair a damage of a certain size, but a lot of small damage, they leave it. That’s where the cathodic protection comes in. It’s going to protect those damaged areas.

Russel:  I guess, Bob, the point I was making is, unlike the older epoxy, where you get damaged in the coating and it can actually exasperate the cathodic protection, this you get a damage in the  coating and the cathodic protection is going to give that cover.

Bob:  This is a cathodic protection-friendly coating, FBE, and it will not disbond. See, it chips and it breaks off little areas, unlike the coal tar enamel, coal tar epoxy, which can delaminate from the pipeline and shield the pipeline from receiving CP current.

Russel:  Yeah. This coating is kind of fused to the pipe itself, versus laying on top the pipe.

Bob:  You’ve cleaned the pipe to a near white metal abrasive blast finish. You have little anchor patterns along the way because of the abrasion blasting. Then the coating fills in those anchors and stays on that pipeline.

Russel:  That’s why you blast it — because that’s what causes it to kind of grab a hold of the pipeline. Interesting.

Bob:  If FBE does disbond, it’s a very local area, and it doesn’t interfere with CP. FBE is pretty good from a temperature point of view. It depends on factors, but a single layer is about 120, 160 Fahrenheit. Double layer is about 160 to 200 Fahrenheit.

The good news is, failure of the coating, failure of the FBE, does not promote external stress corrosion cracking of the pipe body, which tapes can do. It’s a subject beyond the immediate topic here, but when you hear the word crack, you should cringe. A coating system that promotes stress corrosion cracking is not a coating system you want to use. FBE does not do that.

Russel:  Interesting. Again, I guess, because it’s a plastic versus a glass. That’s pretty easy to visualize. You can think of a plastic, even a hard plastic. It has some flexibility, where a glass does not. A glass — very little flexibility. When you take it beyond its stress point, it shatters.

Bob:  Any coating system you have for a pipeline has to have some flexibility because when you lay a pipe, you bend it. It has to at least withstand that bending angle. You’re offshore on a lay barge. You’ve got these J lays and S lays, and pretty significant angles. That coating has to be compatible with that degree of flexibility required at the installation temperature.

Russel:  I guess part of coating design is to know how it’s going to be constructed.

Bob:  Oh, yes, absolutely. Don’t forget the field joints, because how you’re going to coat the field joints are very important.

Russel:  If I’ve got to sandblast and heat up the pipeline to do the coating on the joint, do I have to do the same thing where I’m doing the weld, where the girth weld?

Bob:  Yeah, let’s talk about that. You have two kinds of field joints materials for the FBE coated pipe. One is FBE, the same thing we talked about. That’s the same method, but done in the field. There are portable units.

The other one is to take 100 percent solids, liquid epoxy, blast the area, and let it…You generally don’t need to heat that, where you apply epoxy like you would mixing the resin and the hardener together. But both of them need abrasive blasted pipe ends, around the weld, a few inches either side of the weld.

Now, keep in mind, FBE, the cure time is so quick — it’s under a minute — liquid epoxy, you know, takes longer than that to cure. If you’re on a production run, you’re over the ditch, and you’re trying to get these things done, you can’t put the dirt back into the trench until that liquid epoxy coating is cured.

If you’re dealing with a large length pipeline with a fusion bond epoxy coating, it’s best to use the specialized field FBE application for the field joints, because it cures so quickly, then you fill in the trench quickly. You don’t have to wait for it to cure.

Of course, now you’re requiring special equipment and special vendors, and going to cost you more to do that. It pays off on production rate, so if you have a very large project, it’s going to pay off better. Those are the kinds of field joints.

Now, if you come in and put a tape wrap instead of an FBE field joint, you have now created a very weak link in your pipeline system, because the failure will occur at the field joints, and the FBE pipe body will be fine. You’re going to have failures, and you’re going to have repairs.

Russel:  Right. Let’s move on. Let’s talk about polypropylene…

Bob:  That’s, again, the most recent innovation, and it was driven by the demand for higher temperature. You start off with an initial fusion bond epoxy layer. It’s only six mils thick, so it’s much thinner than the full FBE coating.

Then you add an adhesive, which is about eight mils thick. Then you add the polypropylene outermost layer, which is 50 to 120 mils thick. That’s a pretty significant thickness. You extrude the polypropylene onto the moving pipe that’s in the shop.

You form a solid coating layer or a sheet of polypropylene around it. This is all automated, you have FBE automated, and polypropylene is. The mastic, the adhesive layer, is also automated. This thing now is called three-layer coating.

It’s a much thicker coating. Not only does it handle higher temperatures, like 200 to 280 degrees Fahrenheit, depending on supplier and what-have-you, but you can now take that pipe, and it’s much more resistant to abrasion, impact, and installation damage than FBE is. It doesn’t need this extensive amount of kid-glove-handling that FBE does.

It provides a superior external coating system, but you pay more than you would for FBE, and there’s fewer number of applicators for that kind of coating versus FBE. How do you join at the field wells? What do you do there?

Same thing. You can get this three-layer coating applied in the field through a specialized applicator. You could do heat shrinks. They actually have a three-layer heat shrink sleeve with an epoxy primer and a hot melt adhesive and a coat, a polypropylene external layer, but it heat shrinks.

You put it over something, apply heat, and it shrinks to conform to the shape. I’m going to talk about that in a second, these heat-shrink coatings. These are your two new, modern pipeline coating systems, fusion bond epoxy, three-layer polypropylene. Let’s talk about field joints, if you would like to move on.

Russel:  Let’s do that, because I’m sitting here, and one of the things that thinking about, Bob, as I’m processing what you’re telling me, is that a pipeline, particularly a long run pipeline, it would be very likely that all of these coating systems could exist on a long run pipeline, I would think.

Bob:  Yeah, at the field joints versus the main pipe joints, yeah, you might get two different coatings there.

Russel:  I guess from pump station to pump station, it would be pretty consistent construction.

Bob:  Oh, yeah, look at this way. If your temperature is going to dramatically increase or decrease, you might go from three-layer to a fusion bond. If you’re going from a high temperature to a lower temperature, or vice versa, however…

You’ve got to think about logistics and other factors that may make it easier to stay with one coating type. You’re going to be doing field joints. You want to be consistent. If you stay with one coating system, you’re only going to do one kind of field joint.

There’s a lot of economical situations and circumstances that you’re going to need to consider. You don’t typically mix and match.

Russel:  Right. You wouldn’t do it on purpose, but I was thinking that, over time, as you continue to operate, maintain, and do repairs, and maybe replacements of individual segments and all that kind of stuff.

Bob:  Sure, an example of that is new tie-ins. Let’s say you have an existing line that was built with coal tar enamel, and you wanted to add some tie ins to the line, and add a new pipeline segment. That’s not going to have coal tar enamel. That’s probably going to have fusion bond epoxy. There’s a good example of what you’re talking about.

Russel:  Right. Let’s talk about field joints. Let’s move onto that subject.

Bob:  I talked about the good field joints that are the same that are the main pipe body coating, but there are some bad field joint choices out there. They disbond from the pipe. They wrinkle and fall off, and they shield cathodic protection.

These particularly are wraps, like cold applied tape wrapping, which could be used on the field joint and the pipe body, which we mentioned earlier. That’s a butyl rubber adhesive and a synthetic, and an outer layer which is polyethylene or polypropylene.

The problem with those is that they do wrinkle. They do shield cathodic protection. There’s been a lot of failures associated with these coatings.

Now, can they be successful? The most successful ones are the lower temperature pipeline applications, the ones that don’t get much more than ambient temperature, relatively cool temperature.

The other thing is the heat shrink coating. That can be tape. It can be a sleeve. You put the sleeve over the line. You weld the line together, bring the sleeve over where you welded, and then heat shrink it on.

Or, you have what’s called a cigarette paper. You roll the heat shrink roll over the welded joint, and then you apply heat. It’s pretty amazing to watch. I’m sure everyone’s seen heat shrink at some point in their lives, where if you apply the heat evenly, it just sucks down onto what it’s been applied to and conforms to the shape of the pipeline.

Again, it’s prone to disbondment. It’s prone to cathodic protection shielding. These are the type of pipeline field joint coatings that today a lot of pipeliners are avoiding. Sometimes, so much they prohibit their use in their specifications.

Russel:  Again, there’s probably a whole ‘nother episode we could on this, but just the idea of what’s the trade-off with how you put the joints together, and how you weld them, how you coat them, how you get down in the ditch, all that kind of stuff for different approaches for doing that.

If you’re going to get slowed down or hung up, that’s where you’re going to get slowed down and hung up.

Bob:  Anything you do in the field is what they call the rate-limiting step. [laughs]

Russel:  Exactly, the rate-limiting step, exactly.

Bob:  Everything up to that point is automated. Now, when you start getting into manual labor, then you slow down.

Russel:  Yeah, it gets tougher. Let’s move on. I want to talk about, I know that there’s a lot we could get into. I want to skip over some stuff you recommended, because we’re going a little long.

Bob:  Absolutely, this will be available on the web podcast site, anyway, to have the full text.

Russel:  Yeah, sure. What do you think is the key thing that you’d want people…? I know you’ve got the six steps for being effective, or the six essential factors (see post-podcast insert), and we’ll link that up on the show notes. What do you think the key thing that, just in general, pipeliners should know about coatings? What are the key takeaways from this conversation?

Bob:  I think the takeaway learnings are that fusion bond epoxy, or FBE, it’s the most prevalent specified pipeline coating today. It’s available worldwide, from many applicators, and you can get the field joints done in FBE.

The takeaway on three-layer polypropylene is that it’s not nearly as commonly used, but its niche is it can tolerate the higher temperatures, abrasion, impact, and installation.

If you’re building a pipeline through some rugged terrain, rocky terrain, it’s not going to be handled particularly carefully — you may be in a third world country, that sort of thing    where it’s not going to get the TLC it needs, you may choose to go to the more robust, three-layer polypropylene coating.

Then the last takeaway is the girth welds. The trap is to put in a girth weld coating that’s a weak link in the whole pipeline coating system, which you really want to avoid that trap and put in a coating that’s very compatible with the main pipe coating system.

That tends to be the same coating that you applied for the pipe body, but special application in the field.

Russel:  Right. Well, listen, a lot of times, I try to do my takeaways, but my head’s a little numb, to be honest with you.

Bob:  [laughs]

Russel:  This is a lot of information you’ve laid out, Bob, just a lot, as you often do.

Bob:  I did that to you on the first podcast, and I guess I apologize again. [laughs]

Russel:  No, don’t apologize. That’s a good thing, man. One of the things that’s really cool about hosting this thing is I get to learn a ton. It’s actually fun, because I do like learning about this stuff. It’s just, man, that is a lot. I don’t know how much of it I’ll hold onto, but I know where to go look it up if I ever need it. That’s the good thing.

Bob:  Exactly.

Russel:  Bob, if somebody wanted to reach out to you and get in touch, because I know you’re retired from Exxon, and you work as an individual consultant in this domain, how would somebody get in touch with you?

Bob:  Very easily. You could email me at mr.corrosion@yahoo.com.

Russel:  That is such a perfect email for you, Bob, such a perfect email.

Bob:  Yeah, I will answer your queries.

Russel:  [laughs] Awesome. I don’t know if everybody that listens has gone to the website, but on the website, there’s a profile page for each of the guests. You can get a little bit of a bio and a contact information from them off the website.

There’s also a page for every episode, with show notes, links, a transcript, and all that kind of stuff, so all this information will be there, because I know I’m not going to remember it. If I need to look it up, that’s where I’m going to go to go find it.

I have found myself doing that not uncommonly. Something will come up, and I’ll go, “Man, I know I talked about that.” I’ll go to the website, I’ll look it up, and then I’ll shake out the cobwebs and remember the conversation.

Bob:  I think you’re not alone in doing that, Russel. I think we all do that.

Russel:  It’s not so much that you remember it as you remember to look it up, right?

Bob:  Exactly.

Russel:  Listen, Bob, great to have on. I think there’s probably more we need to cover, so we’ll look forward to having you back again in the future.

Bob:  Okay, Russel, and thank you viewers for staying with me.

Russel:  I hope you enjoyed this week’s episode of the Pipeliners Podcast and our conversation with Bob. 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 would like to support the podcast, best way to do it is to leave us a review. You can do that on the Apple Podcasts/iTunes, Google Play, or wherever you happen to listen. You can find instructions at pipelinepodcastnetwork.com.

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Russel:  If you have ideas, questions, or topics you’d be interested in hearing about, 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.

Transcription by CastingWords