This week’s Pipeliners Podcast episode features Bob Franco, returning for his third episode on the Pipeline Podcast Network, to discuss hydrogen gas and the effects it can have on the pipeline system when blended in.

In this episode, you will learn about the properties of hydrogen – specifically the destructive properties of hydrogen. The episode covers the destructive properties of hydrogen atoms, what types of pipes are vulnerable to the most damage, as well as what exactly is harming the pipeline.

Pipeline Integrity Implications of Blending Hydrogen Show Notes, Links, and Insider Terms:

• Bob Franco is the president of Franco Corrosion Consulting. Bob was a Sr. Materials & Corrosion Consultant for 43 years at ExxonMobil. Connect with Bob on LinkedIn or email him 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 Pipeliner’s Podcasts appearances here.
  • Transporting Hydrogen in Existing Natural Gas Transmission Steel Pipelines from a Materials Perspective by Bob Franco
• Green Hydrogen is hydrogen generated by renewable energy or from low-carbon power. It has significantly lower carbon emissions compared to grey hydrogen.
• Grey Hydrogen is created from natural gas, or methane, using steam methane reformation but without capturing the greenhouse gases made in the process.
• Brown Hydrogen is made from brown coal and is produced via gasification. It’s an established process used in many industries that converts carbon-rich materials into hydrogen and carbon dioxide. As a result, gasification releases those by-products into the atmosphere.
• Nascent Hydrogen is hydrogen in the form of individual atoms, not paired into molecules as it is in the gaseous state
• ASME B31. 8 covers gas transmission and distribution piping systems, including gas pipelines, gas compressor stations, gas metering and regulation stations, gas mains, and service lines up to the outlet of the customer’s meter set assembly.
• Catalyzed reaction is the presence of iron oxide is facilitating the breakdown of the hydrogen molecule into hydrogen atoms
• Hydrogen Embrittlement is a failure process that results from the retention or adsorption of hydrogen in metals, usually in combination with applied tensile or residual stresses.
• Ductility is the amount of strain a steel can withstand before brittle failure and the loss of steel integrity. 
• Fracture Toughness is the stress-intensity factor at a critical point where crack propagation becomes rapid.
• Fatigue Resistance is a measure of the strength, where the loading is cyclic in direction as well as its intensity.
• Dislocation is an array of iron bonds that do not fit exactly perfectly into the crystal structure.
• ASME B31.12 is the standard on Hydrogen Piping and Pipelines contains requirements for piping in gaseous and liquid hydrogen service and pipelines in gaseous hydrogen service
• PTFE (Polytetrafluoroethylene) is a synthetic fluoropolymer of tetrafluoroethylene. Being hydrophobic, non-wetting, high density and resistant to high temperatures, PTFE is an incredibly versatile material with a wide variety of applications, though it’s perhaps best-known for its non-stick properties.
• Read the Pipeline Safety Trust article over Hydrogen Pipelines: Unique Risks Prove Dangerous for Pipeline Transportation here.
• Report: Safety of Hydrogen Transportation by Gas Pipelines

Pipeline Integrity Implications of Blending Hydrogen Full Episode Transcript:

Russel Treat:  Welcome to the “Pipeliners Podcast,” episode 270, sponsored by Gas Certification Institute, providing standard operating procedures, training, and software tools for custody transfer measurement and field operations professionals. Find out more about GCI at GasCertification.com.

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. We appreciate you taking the time. To show our appreciation, we give away a customized YETI tumbler to one listener every episode. This week, our winner is Chris Williers with Ironwood Midstream. Congratulations, Chris, your YETI’s on its way. To learn how you can win this signature prize, stick around until the end of the episode. 

This week we’re going to speak to Bob Franco about the pipeline integrity considerations of hydrogen and natural gas. If you’ve ever listened to an episode with Bob, you know it gets pretty technical. This one does. Bob, welcome back to the Pipeliners Podcast.

Bob Franco:  Russel, it’s a pleasure to be back for my third podcast with this organization.

Russel:  We’re glad to have you. Maybe it’d be good because it’s been a while since you’ve been on. Why don’t you tell us a little bit about who you are and what you do?

Bob:  Sure. I am a metallurgical engineer by degree. I am a corrosion control engineer by practice. I spent 43 years with ExxonMobil and achieved the highest technical level in the ExxonMobil production company for the materials in corrosion control discipline.

Since then, 10 years after I retired, I’ve been working as, basically, a liquids pipeline consultant. That wraps me up in a 53 year career right there.

Russel: Yeah, that’s a minute. I asked you to come on to talk about hydrogen because there’s been a lot of talk about hydrogen and how hydrogen can be mixed in with methane, and all of that. I thought it’d be helpful to get in the weeds technically and talk about what is hydrogen and what are the risks and so forth.

Maybe, that’s a great place to start. I’ll just ask you, what is hydrogen? How is it different from methane?

Bob:  Hydrogen is a colorless and odorless gas chemically written as H2. It’s the most abundant element in the universe, but it doesn’t occur naturally on Earth. It only exists in compound forms with other elements in liquids, gasses, and solids. Examples are water, H2O, and methane, CH4. Atomic hydrogen is not found in nature nor is hydrogen gas.

That’s because hydrogen is so reactive, much more so than methane. It doesn’t form naturally, but it can be produced in many ways. There are six ways that we categorize hydrogen production. We categorize these by color, because the gas itself is colorless. Of the six ways, I want to talk about the first two, which is green hydrogen and gray hydrogen.

Green hydrogen is produced by electricity from intermittent renewables, such as solar and wind, and gray is produced from methane, but that has a corresponding CO2 emissions associated with it. The other methods are a variety of things that affect what we call the carbon intensity of the hydrogen, but green is the least carbon intensive.Brown hydrogen, for example,has a lot of CO2 emissions. 

You start with hydrogen or an atom of hydrogen, which consists of a nucleus, which is one neutron and one proton H+, and it has an electron associated in orbit around that nucleus, but it cannot exist freely. You will not see this in nature.

A molecule of hydrogen, H2, has two hydrogen atoms bonded together, and it can exist freely, consists of two protons, two neutrons, two H+, and two electrons, and sort of combining the two atoms together. Now, it’s the molecular hydrogen that may be blended with methane gas or CH4 and shipped in a pipeline network.

Typically, the blend is 5 to 10 percent hydrogen with natural gas, but up to 20 percent is possible. That’s what we’re going to talk about today. The kinds of things that this hydrogen effect on the steel pipeline, on the seals in the pipeline system, and things such as codes and other steel grades of pipeline that are more acceptable than others, this blends gas service.

Russel:  I’m just going to summarize what I heard you say. I think it’s consistent with what I understand about hydrogen. That is that the atom is reactive, the hydrogen atom has to be attached to something. If it becomes unattached, it seeks to attach itself, which chemically, that’s reactive. Right?

Bob:  Mm-hmm.

Russel:  Then it’s also much smaller than carbon. Carbon atom or a methane molecule is much larger than a hydrogen molecule.

Bob:  Absolutely. The methane molecule is much less reactive and much larger. In fact, it’s too large to diffuse through the solid steel crystal structure. Whereas, atomic hydrogen or H can readily diffuse through steel. The reason it does that is…

Russel:  Yeah, break that down for me if you would, Bob.

Bob:  Yeah, I will. First of all, you say, well, how do I get this atomic hydrogen? I’m going to refer to a new term here called nascent hydrogen. That’s atomic hydrogen liberated during a chemical reaction. What’s the chemical reaction here? ]

You’re putting hydrogen in a pipeline. It contacts the steel surface. Steel surface has rust and other oxides on it. Those oxides catalyze the adsorption of the hydrogen gas onto the steel surface. Then the subsequent breakdown or dissociation of H2 to H.

Now, this is only a small amount of the total hydrogen that you’re transporting, but what happens is that this H resides on the ID surface, and because of a concentration gradient, it migrates towards the OD surface through the thickness of the steel pipeline. The highest concentration will be on the ID, and practically nil on the OD surface.

We have this catalyzed reaction where H2 forms to H atomic hydrogen or nascent hydrogen. Now, even a small amount of methane can have a reaction on the pipeline steel where methane breaks down to a carbon atom and four hydrogen atoms, but this is so much less so than what the hydrogen gas is doing.

When you look at the consequences of methane breaking down to hydrogen, there are no consequences because as long as you stay within the allowable stresses in the pipeline design code such as B31.8, you’ll be fine. It’s really the hydrogen, not the methane, that is going to go into the steel structure and have many adverse effects.

Russel:  I’m processing this as you’re saying it, Bob. Basically, what you’re saying is that the hydrogen molecule is small enough that it actually works itself into the metal matrix. Work its way into…

Bob:  It’s not the hydrogen molecule. It’s the hydrogen atom.

Russel:  Oh, OK.

Bob:  The hydrogen molecule has to break down into two hydrogen atoms before they can migrate through the steel structure. That happens on the pipeline surface because of a catalysis reaction where the hydrogen molecule gets broken down by the oxide rust layers on the steel surface. The formation of nascent hydrogen increases with increasing pressure. 

That’s how some of that breakdown occurs. It’s only the atom that can migrate to the steel. The molecule is too big.

Russel:  That reaction that, we just call it…What you call that reaction?

Bob:  It’s a catalyzed reaction. The presence of iron oxide is facilitating the breakdown of the hydrogen molecule into hydrogen atoms.

Russel:  That’s similar to the process used to take hydrogen off of a carbon atom or take a water molecule and split the hydrogen and the oxygen. Similar reaction or something else?

Bob:  It’s a dissociation, yes, but they could be done differently. In the case of the water, you could apply a large electric current to it, and that will cause the breakdown into hydrogen oxygen. In the pipeline case, it’s occurring under pipeline conditions of temperature and pressure.

You’re not actually adding additional energy into this mixed gas blend to form nascent hydrogen, you’re forming it on the pipeline surface. The hydrogen molecule is so reactive, but some of it will break down to nascent hydrogen. The molecule hydrogen cannot penetrate the steel itself. It just doesn’t fit into the crystal structure.

Russel:  The atom can?

Bob:  An atom of hydrogen (nascent hydrogen) fits really nicely into what we call the body-centered cubic structure of the iron crystal structure. You have iron atoms in each corner of a cube and one in the geometric middle of the cube. If you try to bring those iron atoms together, you condense down the picture so all the atoms can touch each other. The iron atoms can get as close as they can to one another.

That middle iron atom keeps them separated a little bit. That middle one, it creates a space between the other iron atoms, and that’s where the hydrogen finds itself going, and that is what we call the interstitial space. It fits like a hand in a glove. It just goes and finds that right opening. It’s an opening large enough for the hydrogen atom.

That’s funny enough, this is where the carbon atom resides in steel, because steel has about 0.2 percent carbon, it also finds itself into the interstitial spaces between the iron and iron atoms. Hydrogen atoms are much smaller than carbon atoms. It is really small. That allows it not only to fit right in, but to be mobile and to move through the steel structure.

Russel:  It’s looking for something to react with.

Bob:  It is on the hunt.

Russel:  That’s probably not the chemist’s term, but that’s, in effect, what’s going on because a free hydrogen atom was looking for something to attach to, and it’s actively seeking it.

Bob:  When you have this nascent hydrogen formed, and it diffuses into the pipeline, it can degrade the steel mechanical properties, a phenomenon referred to as hydrogen embrittlement. This can cause catastrophic failure of the steel pipeline. Depends on factors.

Russel:  What is actually happening when the metal is embrittled? What’s actually going on?

Bob:  There’s a couple of things. I could tell you the measured effects, the actual things that can be measured in a laboratory, there’s a significant reduction in ductility or tensile elongation. The steel can’t stretch under load as much as it could before without the hydrogen.

Russel:  For those that don’t recall from their high school chemistry, ductility is the thing that allows you to bend a coat hanger without having it break.

Bob:  You get the ductility. Another effect that’s measurable is a rather dramatic decrease in fracture toughness. That’s the ability of the steel to contain crack-like flaws in it without failing. You have what’s called fracture toughness. We reduce fracture toughness by adding hydrogen to the steel.

The next bad effect is fatigue resistance. You will have, on the order of 10 times higher, crack growth rate of cyclic pressure loading in the presence of hydrogen than you would just in the presence of methane.

You have a number of things that are trying to deteriorate the pipeline steel. That doesn’t answer your question of what’s happening, what’s the atomic mechanism going on, and that’s still somewhat controversial, but it appears that two things are going on.

One is, by having the hydrogen fit itself into the space between the iron atoms, the iron atoms no longer have an iron to iron bonding. They have an iron to hydrogen bonding, and that’s a weak bond compared to an iron to iron bond. The cohesive strength of the steel is lost and is greatly diminished.

The next effect is that because hydrogen is so small, and not only does it fit into the crystal structure spaces, it fits into what are called dislocations in the steel, which many of your listeners may not be familiar with unless they’ve taken metallurgy courses.

A dislocation is an array of iron atoms that do not fit exactly perfectly into the crystal structure. There’s a defective crystal arrangement. That defective crystal arrangement, when it moves through the steel, allows that plastic deformation before the steel fractures.

Now, we pin those dislocations from moving. Hydrogen atoms go in there and stop dislocations from moving> The steel wants to plastically deform to accommodate the load, but hydrogen atoms are preventing it from doing that. There is another mechanism of why hydrogen is resulting in this damage.

If I can sum up the damage that we’re talking about, we’re talking about reduction in ductility, reduction in fatigue strength, and a reduction in fracture toughness. Fracture toughness is the ability to have a crack-like defect present without failure, but instead of being non-injurious to the steel, the presence of hydrogen becomes injurious.

Russel:  That’s fascinating. It’s fascinating. I remember enough of my chemistry that I can visualize what you’re talking about in terms of the atom bombs.

Bob:  [laughs]

Russel:  Atom bonds.

Bob:  I’m glad you corrected that.

Russel: I could visualize how hydrogen would work its way in and set itself in between two iron atom to iron atom bonds so that it’s iron to hydrogen to iron as a bond.

Bob:  Yes.

Russel:  Very simplified of course, but fundamentally, that’s what has occurred.

Bob:  That’s what’s occurred.

Russel:  Then the outcome of that effect is what you just listed in the change to ductility and fatigue. 

Bob:  I want to say when the hydrogen fits in, it doesn’t displace any of the iron atoms, it’s fitting in between them. Some other alloy elements like chromium, nickel and all that into steel, they push out the iron atom, and they substitute for it in the crystal structure, but not hydrogen. Hydrogen fits in, doesn’t displace anything.

Russel:  Just changes the mechanical properties of the structure.

Bob:  Changes the mechanical properties through a strong negative.

Russel:  Let’s talk a little bit about how concentration of hydrogen in a methane pipeline is considered when you’re looking at the risk of having these negative outcomes. How does concentration, like how does having more hydrogen in the natural gas stream contribute to this problem?

Bob:  First of all, you’re going to have now a pipeline that has direct contact with hydrogen gas, before it only had direct contact with methane gas. I’m assuming we’re dealing with existing pipeline structures, not a new pipeline to a system dedicated for hydrogen service. This is blending hydrogen into an existing methane and natural gas pipeline.

What would be the concentration of hydrogen in a blend? If you’re doing simplistically and assume that the blend is an ideal gas, so the concentration of hydrogen is going to be the mole fraction of hydrogens, which should be, let’s say, it’s 10 percent, 0.1 one mole fraction.

Then you have the partial pressure of that hydrogen. If you remember where partial pressure is in your chemistry, if you have a gas mixture and this in our case, methane and hydrogen. In an ideal gas, you could treat each of those molecules as separate.

You look at a total pressure, let’s say, as a thousand PSI, but that is made up of the partial pressure of the hydrogen plus the partial pressure of the methane. It could be for a 10 percent mole or mix, you would have 1,000 PSI. You’d have 0.1 times 1,000, or 100 PSI of hydrogen, and then you’d have 0.9 of methane or 900 PSI of methane partial pressure in that pipeline.

You can look at that concentration as a function of the hydrogen partial pressure. Now, I will say that the only existing code for hydrogen gas, which is ASME, B31.12. B31.12 is a new code fairly new, that only looks at pure hydrogen. It’s not looking at hydrogen blends with methane.

My way of looking at this concentration with partial pressure is consistent with how we deal with hydrogen sulfide in the oil field environments with methane. You take the partial pressure of the H2S, and I’m taking the partial pressure of the H2 in this case, because it is still a molecule, but it’s in the pipeline mostly as molecular hydrogen.

You take the partial pressure, so if you all look at the higher the partial pressure, the more influence that hydrogen is going to have. What influences partial pressure? The total pressure and the mole fraction. The more hydrogen I put into the blend, the more hydrogen partial pressure I’m going to have.

The more hydrogen partial pressure I’m going to have, the more adverse effects I’m going to have on my steel. Now, as I said, the code looks at it as the total pressure of hydrogen and the strength grade of the pipeline steel. B31.12 does not look at partial pressure hydrogen, because they’re transporting 100 percent of hydrogen.

There’s no such thing as a partial pressure of a gas when it’s not blended with anything else, so it’s just the hydrogen pressure. The code does talk about hydrogen pressure in it and talks about the service factor that you have for different grades of pipeline steel. In general, the higher the strength of the steel, the more adverse effect the hydrogen is going to have on that pipeline.

So you have more percent damage as the pipeline grade gets toward X80 grade of pipe versus an X45 or 52 grade, or grade B of pipe. The concentrations, this is the amount of hydrogen that you’re asked your question, how does the hydrogen concentration affect the damage? That depends on what steel pipe you have and the hydrogen partial pressure of that gas being transported.

Russel:  To me, that’s a little counter intuitive that the stronger the pipe, the more negative impact of the hydrogen.

Bob:  This is a known fact in the oil business with full well stream pipelines, which we look at with hydrogen sulfide. The more H2S you have, the more damage you get. The higher the strength and the greater the partial pressure of H2S, the more percent adverse effect it has.

What that means is that you really don’t get a benefit using the highest strength grades of pipe because high strength grades get damaged more effectively by hydrogen. You have to limit yourself to low strength grades. It’s not counter intuitive if you think about what’s going on. It’s the amount of hydrogen in the steel.

It’s the microstructure of the steel pipe that affects its ability to accommodate that hydrogen. How much degradation does it do to the percent elongation, to the fracture toughness, to the fatigue life? You will see that the actual experimental data will show higher strength steel grades will be more adversely affected than the lower strength grades.

Russel:  Yeah, so I believe you, Bob. I’m just trying to get it clear in my mind, as I’m trying to picture it. Is that because the higher strength steels have a higher concentration of these iron atoms that could be…?

Bob:  No, they have less ability to accommodate plastic deformation, typically. You get less ability to  tolerate plastic deformation, and more intolerance to the presence of cracks in the steel structure, which means that a smaller crack may fail catastrophically in the presence of cracks. Whereas in a lower strength steel, that same crack size may not be a problem.

Russel:  It’s basically the flaw has aligned with the strength of the steel, so the stronger the steel…

Bob:  Absolutely. With the strength in the steel comes factors such as the microstructure. I’ll throw some terms out, ferrite plus pearlite microstructure, tempered martensite microstructure, bainitic microstructure. Those microstructures come from the heat treatment of the steel. Some of those microstructures are much more intolerant to hydrogen than others.

You have to go to a low strength, fairly conventional X42, X52 microstructure, and then you can tolerate some amount of hydrogen. Let me make it clear, if I’m one of your listeners, and I’m being asked by my management to blend hydrogen into my existing methane pipeline, I would push back as strongly as I could until they threaten to fire you, because it is not going to be a good thing to do.

You have to understand the situation you’re walking into. That situation requires strong analytical techniques, such as fracture mechanics to make sure that you know how tolerant your pipeline is. If you’re dealing with conventional low strength steel pipelines, which is generally where the hydrogen has been blended so far, X52, you don’t have to do a whole lot for that.

They have some broad guidelines in the industry. Stay below 20 percent hydrogen. Stay below 50 percent yield strength on your stress levels. You could tolerate that hydrogen blend up to about a 20 percent level (mol fraction). Those are the guidelines out today. That’s subject to change because we have very limited experience now with hydrogen blends. As we get more experience, we’ll learn more.

Putting hydrogen into an existing pipeline infrastructure, the hydrogen pipeline, the code B31.12 gives you two approaches when it comes to designing that new infrastructure. One is, keep it safe, keep to the low strength grades and relatively low pressure on the system. Then you could use it at 50 percent yield in a class three area where there’s people and structures around.

That doesn’t change from what we have today in B31.8 gas pipeline code. I’ll give you an example of what the new code has in this. In B31.8, you take an X52 grade operating at 2,000 PSI. You say, “OK, let’s get back to our 20 percent hydrogen, 80 percent methane blend.” 2,015 is the absolute pressure when you’re working with partial pressures. You can’t use gauge. You have to use absolute.

2,015 and 20 percent of that. It’s a class three area. You can see you’re running at about 400 or so, 403 PSI hydrogen partial pressure. Some would say for 400 PSI hydrogen B31.12 would say, you could go up to 0.5 service factor. That’s 0.5 times the yield strength, or 50 percent of yield in a class three area, up to 2,000 PSI total pressure.

You could go up 50 percent of yield strength, which is pretty much the same as what B31.8 would allow for a class three zone pipeline. Let’s look at X60. Remember, for X52, the service factor was 0.5. For X60, the code reduces it to 0.437 times the SMYS at up to 2,000 PSI. Let’s look at X80. X80, the service factor is reduced to 0.357. You’ve gone from 0.5 for X52 to 0.357 for X80.

That’s the effect that this code is now saying, X80 is so much more susceptible that you have to downgrade the amount of stress on your pipe. That’s the trade off between the higher strength and the adverse effects of hydrogen.

Russel:  Interesting. This has been absolutely fascinating, Bob. I’m so glad you agreed to come on and talk about this, because for the first time, I’ve known about the effects of hydrogen but I didn’t know about the mechanisms that cause those effects. This has been really educational for me.

Bob:  Right now, the consensus is stay below (<50%) the specified minimum yield strength (SMYS) for grades X42, X52 and grade B. Use those pipes, with X52 being the highest allowed. If you have forgings in your system, SA73/72, which is a thin wall steel forging, has worked well in hydrogen. Right now, operators are playing it safe.

They’re keeping the stress levels to 30 to 50 percent of SMYS, which depending on circumstances, is going to be below what B31.8 would allow. We have some conclusions here about what I have tried to say to the listeners.

If your pipeline system was initially not designed for pressurized gaseous hydrogen transport, you need confirmation of fitness for service of this pipeline system in the presence of hydrogen. You have to look at the mechanical loads, the cyclic loads, the microstructure of the pipe, the chemical composition of the pipe.

I’m assuming it’s all welded pipe and you know the gas pressure, gas composition and temperature. It gets very complicated. If you want to narrow it down to the simple things, that’s why I said, if at all possible, push back on blending. If not at all possible, then maintain less than 20 percent hydrogen in the blended gas. 

Do not use pipe grades that exceed the yield strength of API 5L grade X52 without doing extensive testing and analysis of the steel, the mechanical properties, the fracture properties, and particularly the fracture properties in the presence of hydrogen. Do not exceed 2,000 PSIG in the blended gas.

One thing I haven’t touched on yet, which is the soft materials, seals and gaskets. Hydrogen, being the small, reactive material it is, will penetrate the soft materials. You’re looking at things like natural rubbers that get very badly affected. Viton will be affected.

The preference in hydrogen service comes from the preference in hydrogen sulfide service. Use perfluorinated thermoplastic seals over elastomeric seals. Those are going to be perfluorinated, meaning they contain fluoride ions. PTFE, polytetrafluoroethylene, is the most common. It’s like a Teflon grade of a gasket. Stay away from natural rubber. Stay away from some of the lesser grades that are not fluorinated.

In H2S environments, we’ve proved gaskets get adversely affected by H2S, I believe they will also be, and the literature suggests that so far as well. A lot of gasket materials will be affected by hydrogen as well. It’s an overall materials review. It’s overall what the risk is associated with a failure, so overall assessment of how well my pipe can tolerate this hydrogen.

Russel:  Bob, again, I really appreciate this. For the listeners, we’re going to do a couple of things on this episode. One is Bob was so kind to write a paper on this and provide it. We’ll link that up in the show notes.

Then, the listeners might also be interested to know that the Pipeline Safety Trust recently published a white paper on the risks associated with blending hydrogen into natural gas systems. There’s some pretty strong recommendations in that paper as well. We’ll link up that resource as well for anybody that’s interested in reading that material.

Hey, Bob, thanks for coming on. It’s great to have you, as always. You’re making my head hurt a little bit, and that’s a good thing.

Bob:  That’s my job.

Russel:  You do it well.

Bob:  OK, Russel. Bye bye.

Russel:  I hope you enjoyed this week’s episode of Pipeliners Podcast in 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 and enter yourself in the drawing.

If you’d like to support the podcast, please leave us a review on Apple Podcast, Google Play, Stitcher, SoundCloud, or wherever you happen to listen. You can find instructions at PipelinePodcastNetwork.com.

Russel:  If you have ideas, questions, or topics you’d be interested in, please let me know either at 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