Introduction
Cameron Croft:
All right, everyone that’s joining us right now, this is our first Virtual Roundtable. This one is going to be brought to you because of troubleshooting issues that we’ve had in the past. So what I’ve done, is I’ve invited some subject matter experts to come on as panelists today. So, to kind of go through and get this thing started.
Cameron Croft:
To stay in the know, if something happens, I know a lot of y’all might be at work, working remotely. Kids might walk in, internet might go out. So, if you have anything in particular, reach back out to us, but we are going to put this video up on our website, and with a transcript, so that way, you can do a quick search find if you’re looking for something in particular.
Cameron Croft:
Meeting the speakers. So my name is Cameron Croft, I’m CEO of Croft Production Systems. I’m just going to act as a moderator. I’ve got enough smart people on this, I can just go with them. But, we have Chris Smithson joining us, director of engineering for Croft Production Systems. We have Jesus Olivares, CEO of Osynergy, which is a manufacturing facility. Back end for him his manufacturing, production, processing equipment pressure vessels, and he’s done a lot of design work for the oil and gas, and private sector, or construction, civil.
Cameron Croft:
We have Terry Nelson, with WPI, Waukesha-Pearce. He’s a manager in technical services, focusing on glycol systems, production equipment, and processing equipment. Coming from his background, really focusing into the glycol systems. He has seminars that he puts on. But all three of these speakers were able to join us today, so, we’ll get started with them.
Cameron Croft:
The topic highlights that we wanted to discuss, now we do have some questions that were given to us beforehand. But we want to go over glycol, dehydration, solid desiccant dehydration, amine plants, JT plants, and fuel gas. But these are just topics. If there’s something in particular that you all really want to discuss, we’re just going to let this conversation go with that.
Cameron Croft:
So, how this is going to work, is if you’ve got a question, a specific question, y’all can write it in the chat box, or the question Q&A answer section. If y’all want to discuss it, you can write it in. But if you say, “Hey, I have a question.” Once it gets to you, I’m going to unmute you, so that way, you can actually just start talking with the subject matter experts.
Cameron Croft:
We’re going to have one person take the lead. So, in this case, it might be Terry Nelson, they’ll take the lead over the questions, start answering. And then once he’s gone in, Jesus or Chris might come in, follow up if, there’s any gap, or some things that they want to add to the question. So, we’re going to get started now. I’m going to stop sharing so that way, we can see everybody’s faces.
Cameron Croft:
So again, if you have a question and answer, y’all can type it into the chat, type it into the Q&A section. And then, that way, we can kind of get started with this. But people, there’s a lot of questions that were shipped in beforehand. So, I want to first go over Chris, if you can kick us off. The question was, “Fuel gas for compressors, what are some quick tips to maintain fuel gas composition to prevent compressor shut down?”
Maintaining Fuel Gas Composition
Chris Smithson:
So, really, you’re going to have to look at your fuel skid, and where you’re pulling your fuel gas from for a way to make sure that you’re getting the best quality that you can. If it’s coming after process equipment, or if there is process equipment, you’re not coming after it, like let’s say you have a DI on location, and for some reason you’re choosing to not pull after that DI, that’s a quick move that you can pull from after the processing equipment to get a little better quality gas, making sure you’re pulling after all available separation, so that you’re not getting gas that may have any sort of condensate.
Chris Smithson:
Just being considered of what the temperature is changing, especially if you have rich gas, if there’s a temperature effect, changes that are happening, like if you have a long pipe run between where you’re pulling the gas, and then your actual compressor, are you seeing temperature changes happening there? That’s a good way to make sure you’re not gonna have condensate problem falling out, but really, if you’re having condensate issues, a proper fuel gasket is really the only way to make sure that you can run throughout most of the year without any problems.
Cameron Croft:
So, a proper fuel gasket on a JT or on a separator?
Chris Smithson:
Yeah, I mean, you can make them work, use the regulator with some separation. It really depends on the quality of the gas that you have. And if you have rich gas, you’re going to want a JT unit, something that’s going to warm the gas back up again, with the heat exchangers. So that’ll give you a much better quality, because you’re going to actually lower the BTU, and have a much bigger hydrocarbon dewpoint depression, with the gas with the JT unit, then you will just a fuel skid.
Chris Smithson:
If the gas is pretty clean, then you can get away with just to dehy, and a regulator, dehy and the gas can be a big improvement, as Terry can attest. I mean, a glycol unit can do pretty good at taking condensate out of a line. It’ll suck it up, and hopefully get separated on the regenerator. So, having clean, dry fuel gas can really help, and get rid of a lot of the problems that you may see with your fuel gas.
Cameron Croft:
That’s good. Jesus or Terry, did you have anything to add to that?
Terry Nelson:
He pretty much covered everything that was in my mind. Of course, now when you look at the fuel gas, the dehy is downstream with a compressor, especially when you’re looking in gas lift situations, at a lot
Advantages of NACE VESSELS
Jesus Olivares:
Well, with the NACE process, really what you’re getting is a product that meets certain requirements. In this case, especially if you’re dealing with any H2S, or sour gas, then it’s going to help you in the long run. It might cost you more at the beginning for capital costs, but you’re basically ensuring that you’re not going to have stress cracks, which eventually, we see you have cracks, you’ll have basically leaks, which then you’re going to have downtime, you’re going to have repairs, et cetera.
Jesus Olivares:
Now, most of the materials, especially on smaller sizes are already to spec, right? So, they’re already good for NACE, so you’re not really adding any additional costs there. Is it worth it? In my opinion, it absolutely is if you have those conditions. If you don’t, and it’s larger, specialistic pressure vessels, then you’ll save some money by not requesting the NACE.
Jesus Olivares:
Now one of the things that I like to ask is, you have NACE, and then to me, it depends on the level of sour service. I mean, some people you could get threaded, basically threaded piping, and fittings, and need NACE. But if you have high H2S, then I would recommend it, I will go off line. So at the long, at the end, it is worth meeting your requirements. It’s going to save you a lot of downtime, and headaches down the road.
Jesus Olivares:
Some of the things that are overlooked are probably in the instrument side, where they say, “Okay, yeah, it needs NACE.” But if you didn’t order your instruments to have your seals, and gaskets, and so forth to meet NACE, then those are going to go out. The other part is the welding side, and needing to have a qualified procedure to meet NACE requirements. Then your materials are going to be great, but you’re going to have failures at your well.
Jesus Olivares:
So, those are just some of the things to also look at, when you’re looking at NACE. It depends. Flange materials is going to cost a lot more than threaded. So, those are all things you have to ask yourself. At what point do you want to go from not NACE, to NACE threaded, to NACE flange materials. So, I think it’s very well worth it to look at those, and will NACE [inaudible 00:11:06] be required.
Cameron Croft:
Yeah, Chris, did you have anything to follow up on that? I know you’re dealing with some NACE, and some proposals for NACE right now.
Chris Smithson:
Yeah, we’ve gotten requests in for it before. I know, one thing that clients try to do is they want to try to dehy… Well, I’ve heard they think it’ll work. But they say, “Oh, if we dehy the gas, then if you get rid of the water, then you don’t have the corrosion issue anymore with H2S.” So they’re like, “Oh, it’s like 10,000 ppm H2S. As long as it’s dry, then you’ll get rid of all of that corrosion issues with it.” Which that’s not… For one of the mechanisms of H2S corrosion, that is true. But for what Jesus was saying, with the stress cracking, that’s not a water dependent corrosion issue.
Chris Smithson:
I would be curious to hear, Terry, if you have some input on, have you run real sour service dehys in the past? I mean, a trade tower to me, just… We’ve seen them in H2S service, they’re the units that have been in H2S service, not operational. So, I’m not really sure about that. But just, I couldn’t really imagine running a glycol unit, and H2S service, trying to keep that thing operational for more than a year or two.
NACE Glycol Units
Cameron Croft:
Well, that’s actually the follow up question they had is, “Work with any NACE glycol systems, what are the areas of concern?”
Terry Nelson:
Well, I’ve actually built a completely stainless steel dehy before, because a customer just wanted to go to that extreme. We actually suggested that they limit, they go to NACE controls. And you can buy pumps, and different things that meet those standards. But as far as like the reboiler shell, and all that stuff, it’s not really necessary. It just depends on how far you want to go.
Terry Nelson:
Most customers, when they go down this road, Jesus said, they deal with the connections, the valves, and regulators, making sure all that meets the standard. And then they’ll go with maybe a stainless steel fire tube. Because when you look at a dehy system, that’s where the corrosion occurs. That’s where the temperature is, that’s where the gas meets the glycol. And usually, where the liquid stops, and the vapor stage starts, that’s where the corrosion occurs, because that’s where the air is present, or the gas is present, and the corrosive line usually follows the liquid level line.
Terry Nelson:
So, a lot of people want to do a stainless steel fire tube. I’ve done stainless steel columns, because escaping steam gets corrosive sometimes, in that atmosphere. The most important thing is, is to look at it with common sense, and just don’t dive into it, and build something that’s cost-prohibitive to really what your concerns are.
Terry Nelson:
The biggest problem is where you have dissimilar metals meeting. If you build a stainless steel fire tube, then you better build a stainless steel tube sheet. Because if you take a carbon steel tube sheet, weld a stainless steel fire tube on it, that’s what happens sometimes. Then the corrosion will occur where those dissimilar metals are meeting. And that’s usually the problems that happen. But you can go as far as you wanted to when you start diving into that. But most of the time, you need to get with an engineer, design engineer. Somebody like Chris, or Jesus, or just somebody to pull you back in from the ledge.
Jesus Olivares:
Well, Terry was bringing up some really good points. The fact of just understanding what the customer is going to need at the end. And nowadays, especially with cost, we’re all looking at how do we reduce costs? Of course, we balance costs with the actually safe side of a design, right? So, we have not built an all stainless dehy unit, but we have had a combination.
Jesus Olivares:
One of the other things we’ve done is we’ve done internal coating, to help reduce, maybe not… If they don’t want to go to stainless steel level, you internal coat, and add at least another layer of protection. But we got a little thicker on the metals, knowing that you’ll have some corrosion, and loss of metal. So, that might be another option when you’re trying to balance costs, and the H2S side of it, or the sour environment side of it. This is similar, wells material, obviously you have to have… That’s why you qualify your procedure to be able to meet sour service, send the testing, and make sure it’s able to handle that.
Chris Smithson:
So what about cladding vessels, Jesus, like stainless steel cladding internally? Is that cost-effective at all, for trying to get some extra corrosion protection?
Jesus Olivares:
Well, we don’t really have those capabilities, and I have some experience on it. It’s an option. I have not seen it very often to be honest with you. I think at the end is, you either go thicker on the metal, or you go with the other option. Now, I believe the bigger you go, that would make sense, just because it’s going to be a lot thicker, and a lot more costly to build, just by changing the materials back on it.
Would a turbulator help reduce hot spots in a firetube?
Cameron Croft:
Well, we actually had one question come up. So, this is our first live questions, so I’d like to kind of put some priority onto it. It says… Would a Smick turbulator help in reducing hotspots in fire tubes? Is that a manufacturer? Or did they just type really quickly?
Terry Nelson:
I’ve actually moved more turbulators than I have installed.
Cameron Croft:
Really?
Terry Nelson:
Yeah, back in the 80s, early 90s turbulators were the thing. And we would install them on the downstream side of a fire tube, and it was just there to expand surface area. Great idea when you think about it, but it’s also a good trap to catch stuff, soot, and different items. And it was a vibration point. Vibration means ware, and we had fire tube damages because of it.
Terry Nelson:
Now, it could have just been the design of the turbulators. At those times they were honeycomb, eight or 10 feet long, and it was just designed that heat, something to bounce off of in the downstream side of a fire tube. Now, we all know that flame impingement is bad, and that’s when a burner is not dead center, and it’s causing the flame to actually run down the fire tube wall. That’s with an eclipse style
burner. That’s never good. You want the burner in an eclipse style burner going dead center down the fire tube, and expanding heat out.
Terry Nelson:
Now, when you look at the Clear Rush, or Gold Rush, or there’s four or five manufacturers that make these inserts into burners, and they actually close off the fire tube. You have little vents you open up, little fins, and then it has a different style of burner that operates at three to five pounds of pressure. Those burners are designed to create a swirling effect, and that’s causing the flame to swirl around the fire tube as it goes down the fire tube. That’s a different philosophy, than the actual flame running down the tube wall.
Terry Nelson:
So a turbulator, what a turbulator is, is just a way to expand the surface area of the fire tubes, to get more time for it to stay in the fire tube, before the heat is lost out the stack. We never want high stack temperature. We want high fire tube temperature. When you have a high temperature, any [inaudible 00:20:28] 650 and 100, then you’re losing BTUs out the stack. And a turbulator is a great philosophy of slowing down that process, because that burner’s natural draft, if we can slow that down, but it has to be designed just right. Because if you got too much, then you’re starving your system for air. So, you have to be able to draft, so that the turbulator design is critical. But they do work.
Chris Smithson:
I think like you said though, using a lot of wear points, vibrations and stuff, and especially since… I mean, I’m sure you get a harmonic sometimes, with the way that the burner may start pulsing, and I’m sure that vibrations with that. But a lot of burners, they’re on off service, so that things constantly… If it’s just something you slide into a fire tube, it’s constantly expanding, and contracting, which can cause wear points if it’s not welded every single point of that thing that’s such in the fire tube.
Chris Smithson:
So yeah, some of the… I’ve seen some interesting designs for them. No one’s ever wanted to pay for the upgrade for it. But, in concept, it seems like a really good way to get a little extra fuel efficiency. I think that’s really what you’re getting with it, is fuel efficiency, and you’re going to save some NCF on your burner system by squeezing that heat out of the stack temperature.
Chris Smithson:
But yeah, most of them are just slide ins, and I wouldn’t feel confident that something’s going to last for a decade or more, that just constantly rubbing on the inside of that fire tube. But we do use them in heat exchangers like the JT units, they are a good way to boost efficiency in like shell and tube exchangers, especially liquid exchangers, they can have a really good effect on the efficiency of the liquid exchanger.
Most Repaired Areas on Equipment
Cameron Croft:
Well, it could be. All right. Well, to follow up on the repair conversation. One of the follow up questions we had, Jesus, if you don’t mind to take over this one, it says, “In your experience, what are the most repaired areas, contact tower failures, separator failures.” And then they just wrote, “Every equipment.” But let’s just keep on with the glycols, and separators. I know your company does a lot of repair work. So, where do you see the most failures happening?
Jesus Olivares:
By far, where we find most of the repairs are around nozzles, whether they’re in the liquid level or they’re in the gas side, where it just has a corrosion point. Whether they’re in the inlet, or you still have drains, by far they’re around… And especially around the well to nozzle connection, for whatever reason. Whether it was not really a NACE certified procedure.
Jesus Olivares:
So, therefore you have some stress cracking, or in this case, some pinholes developing. But by far, that’s it. The next level we see it is around they get worn out, there’s no cleaning there, it’s a lot of solids and stuff like that. So then we’re having to go in there and cut the head, and replace pads. Those really are the two major, as for separators on the tars.
Jesus Olivares:
Again, nozzles are a big factor there. The other we see is around the trays, whether, like we talked about on the previous webinar, we had a contactable, just it was a quick weld, and they had a leak. So, around the well areas seem to be where most of the failures occur. It can be just a poor well, in our opinion, but those seem to be more of it.
Jesus Olivares:
We don’t really see much of the other areas impacted. The shell might get a little bit of wore out and stuff, some pits and what have you. But, a lot of that has to do mainly with the property they’re cleaning, or it just stays like that for a long time, no maintenance, or preventive maintenance. And that’s what we seen a lot more of the issues.
Cameron Croft:
Okay, so if those are the kind of the key areas of failure that you see, Chris or Terry, the follow up on that was, how do we prevent that? How do operators try to increase the longevity before repair work needs to be done?
Terry Nelson:
Well, we do regularly scheduled UT exams. You have a predictive maintenance program. I’ve been on that soapbox for 25 years. We have to schedule downtime, it’s much better than unscheduled downtime. So, when we can have somebody go out and do relief valve testing, regular maintenance, and then predictive maintenance, where we’re doing things that are letting us see into the future.
Terry Nelson:
If you do UT testing, there’s a reason why you put those little stickers on there, that shows where you tested it, and what the thickness was. If you go back and check that every so often, on a scheduled basis, you can figure out where the waves are, where the fissures are going to be created. When gas and liquid flow, along a vessel like a wave.
Terry Nelson:
And it’s carbon steel. Once something starts following a pattern, it’s like erosion at the beach, you’re going to have some fissures develop, and sometimes gas will strike a particular piece of point in the vessel, and then bounce off. And that’s a wear point. And if we have regular maintenance, and when we do those UT exams, and there’s some great companies out there that do a lot of other predictive kind of non-destructive testing on different vessels, where they can be UT combined with some [Voroscope 00:27:34], and there’s another ways to check vessels.
Terry Nelson:
We do that when we pull fire tubes on glycol units. We inspect it, and then we see some pits, we UT those areas, we make a map of the fire tube, and we measure those points, so next time, we see if it’s getting worse. Because if we can catch that spot and make a repair, you don’t necessarily have to replace the whole fire tube, we can make a repair, and put it back in service, versus it gets a hole in it, pours into the fire tube, and then it comes out the flame arrestor, and onto the ground. Now we got soil remediation, we’ve got unscheduled downtime, and much more expensive repairs.
Chris Smithson:
Yeah, I think low pressure vessels are usually where we see the leaks on stuff. I mean, all the vessels we’ve hydroed over the years, and seeing like pinhole failures or something, it’s usually on, if it’s a vessel failure, it’s usually like the cheaper little fuel pots, or the cheaper flash separators. Those are areas that… Those units, that they’re so thin to begin with, that they can risk wearing out, and having corrosion. Especially if they’re put in a service that they’re not really meant for.
Chris Smithson:
Any H2S will just chew through the little fuel pots, and Terry had some good info in the dehy presentation about monitoring pH in glycol units, and making sure that that’s not eating away different areas of the system. It’s pretty important. Filters can tell you a lot if you have like a glycol unit, or amine plant, something that has filters.
Chris Smithson:
Analysis of what the filter is picking up, if you actually cut one open, scrape it and send it off. I mean, if you have a bunch of iron stuck in your filters, then you have a problem, something’s being eaten away. So, those, like Terry was saying about preventative maintenance, I mean, you can learn a lot if you actually monitor, and log it, and see how things are changing over time, can give you a really good indication about what’s happening in that unit.
Terry Nelson:
Someone asked me one time, “Where’s all this iron coming from in my glycol sample?” It’s the contact towers, the vessel wall, it’s the fire tube. It’s iron that used to be intact, but now is in liquid form.
Cameron Croft:
That’s right. Well, we actually have one participant, when they were signing up, they come from a sand separator company. So, dealing with sand separation, I imagine they have to deal with a lot of wear and tear. But Terry, I like what you were saying earlier about that predictive wear and tear. Like all the points, like, you know these are gonna be the top points that will fail first, because they handle the flow, they have the 180 turns.
Terry Nelson:
Right.
Cameron Croft:
So having that predictive… It just gave me a business idea on our side, because we handle a lot of leased fleet. So if you come back, and you bring it, you say, “We need to lease UT these points, see where they are.” Because if they’re failing, or if they’re good, then most likely, the unit’s going to be good. But if they’re failing, we might as well just do a full check on all the system, at that. More predictive, I guess, on our returned equipment.
Terry Nelson:
Yeah, there’s preventative maintenance, PMs, And then there’s predictive maintenance, you’re looking further down the road, to where in your situation, you can predict when you’ve got to replace that piece of rental equipment before it fails on the customer’s location.
Cameron Croft:
Yeah.
Terry Nelson:
And then that helps you manage your fleet.
Cameron Croft:
I mean, we sell equipment, but our lease fleet, we don’t start making good money until years and years down the road. So, if it doesn’t last years, and years down the road, we’re just shoot ourselves in the foot. And that actually kind of goes into one of the questions that we had Jesus again, this is probably for you. But, techniques for long term storage of equipment. I guess, they were talking about… Or, you build equipment new, and ship it off? I mean, you ship stuff all around the world, how do you properly, I guess, get it ready for shipping, and long term storage?
Jesus Olivares:
Well, I think one of the first questions is understanding whether it’s going to be for long term storage. Most of our stuff, by the time we complete it, I mean, they’re getting used within a month, right? So it’s short term. For long term, you’re really going to have to prepare for it, I mean, you want to make sure all your threaded connections are greased and plugged. If you have flanged connections, you want to be able to grease the face, and make sure you cover it up.
Jesus Olivares:
And then, we like putting at least a minimum five pounds, up to 20 psi of nitrogen, to make sure it stays, without allowing any oxygen, and so forth to get in there. Of course, all it is, is making sure upfront that it’s properly clean, it’s dried up. There’s no scaling, no solids, or any of that kind of stuff. Because even when you do hydro, you still have some of those things that you have to worry about, and make sure you’ve dried up, and cleaned it up.
Jesus Olivares:
So, when we ship stuff out, the packaging needs to be right. So, one of the first things we need to understand is whether it’s going to be for the long term or not. If it’s long term, those are the basics. Even when a customer says, “Hey, just do an enamel coating.” We’re not much of that. Our experience with enamel coating, they don’t really last, they get pale real quick. So we like to go with polyurethane.
Jesus Olivares:
So, I’m not sure if it’s my internet connection now. I got a note on my screen that it was acting up. But, that, in general is what we tend to look for, when we place it on a… Whether it’s a skidded vessel, or not, or whether it’s by itself, it’s just how we support it. If it’s going to be sitting around for a long time, you don’t want to put it on the ground, obviously. And then the metal to metal contacts is one of the biggest things you want to look out for, because when it condensates, rains, moisture, all that kind of stuff, it gets trapped right there, and that’s where you’re gonna have a lot of corrosion points, from just staying out there, right?
Terry Nelson:
One of our biggest problems when I was the manufacturing director, in one of my previous lives, was knowing we’re shipping that from South Texas, where is it going? Is it going to go to Pennsylvania, and then set there through a winter, before it’s used? We built some oil stabilizers one time that had heat exchanger bundles, and collection headers on the outside of the vessel, and they were all insulated.
Terry Nelson:
So, at some point, either hydro test water, or some flanges left open, and rain rained down, filled those collection headers up with water, then they sat for six months through a complete winter cycle. So, when we went to start the vessels up, of course, the ice had expanded, and broken them, split them open. Nothing is more powerful than ice.
Terry Nelson:
And so, it was under the insulation, so nobody knew. So when they went six months later, to… And that’s where Jesus’ point, is it short term, or long term? They want to put gas to them, all of a sudden, why is this gas blowing everywhere? Because you have ruptures in the headers, from sitting through that freeze. So it’s really important to know where it’s going, how long it’s going to sit there, because there’s things you can do to keep the damage from occurring.
Cameron Croft:
You were saying earlier about drying them out, getting the hydro test water, because we run into a few of those issues too, where you try to blow out as much of the… You pressure it up, even trying to get all that water out. And some of the lowest possible water sits. Jesus, how do you go about, because imagine you have to follow your code that you’re following, but how do you get rid of some of that stuff, the water? How do you pressure that out? Just air compressor to it, or?
Jesus Olivares:
Well, if you just put air compressor, even air, an air compressor, you’re still going to have moisture. So, you dry as much as you can, but you’re still putting some moisture back in there. So, the best thing is just having dry air. So, I mean, when you have to do that, you either have to have a dryer ahead of your air compressor, to make sure that what you’re blowing in there is actually dry air, or desiccant, right?
Jesus Olivares:
So you put something in front that’s removing all the moisture, so that the air going into your equipment is actually dry. The other way, of course, is more expensive, would be trying to use some of these other airs, [inaudible 00:37:03] and so forth, and try to push it. Now, everybody does something a little bit different. Either you could use a tool, and measure what kind of moisture you have. I mean going things through one end, and out the other. You could put even a rag, and see how much moisture is still coming out of that rag. So, just different ways that you can look at ensuring that whether it’s already dry or not.
Chris Smithson:
It can be tricky, because any sort of scaling, or corrosion on the inside of the vessel can definitely hold water. It can be difficult to dry them out, we noticed that with our refurbs, that they’re little trickier to dry, because of the texture of the insides can can hold a lot more. And that can be tricky to dry out.
Terry Nelson:
We do actually have procedures for short term, and long term storage of vessels. I’ve got four or five vessels, complete dehy systems right now, that have been in storage for almost four years. We have nitrogen purge, as Jesus said, on them, we’ve got nitrogen bottles that are sitting on site. And we have regulators holding pressure, and then they have to be inspected. You have to have somebody go check on them, make sure there’s no leaks, make sure the nitrogen is in supply, it’s not ran out, because it will leak. There’s going to be leaks.
Terry Nelson:
So you have to check that stuff. You can’t just plug a vessel, fill it with water, and count on it being stored. That’s why I Jesus’ first thing he says is, “Short term or long term?” There are differences.
Cleaning Out a Vessel After H2S Service
Cameron Croft:
On that, we actually just had a follow up question from Paul. He said, “How would the team recommend cleaning a vessel, and associated connections after service and high H2S environment? So, I guess Jesus, I know you deal with H2S. What would be the code on that? How would you clean that?
Jesus Olivares:
Well, by the time we received the vessel, we actually ordered that they would already be cleaned. And especially because some of these items, we don’t know where they’re coming from, some of them might have even norm. So, you have to check for all those things. But in my, like Terry said, past life, probably doing like a caustic wash or something of that sort to actually remove.
Jesus Olivares:
One of the biggest thing is, all this tends to trap along the wall of the vessels. So even when you think you are cleaned it and so forth, if you’re not doing any kind of a sniff test and so forth, as soon as you start cutting anything, [inaudible 00:39:50] to work on it, for example, that all starts coming out, so you get all those fumes out, and what have you. So, my opinion, would probably a caustic wash of some sort. Terry probably has better ideas on that.
Terry Nelson:
We use a soda ash. We do acid flushes, or we actually go out, and clean vessels with a chemical cleaning, then we follow it with a muriatic acid mixture. And in an H2S situation, we would take our hoppers, and add some soda ash to the circulating water, and that would [inaudible 00:40:33] it, and bring down out of the acidic range, and bring it down. We also have to mix that soda ash with the solution that we’re cleaning, when there’s H2S, or when we’re using an acid, so the vacuum trucks can actually receive the wastewater. We have to neutralize it. We do the same thing.
Chris Smithson:
Yeah, we do soda ash clean outs on our little amine plants, and we bring them back. Before we take them out of service we’ll yank all the amine, and do a soda ash water mix. With H2S, certain amounts of it can actually be protective to the steel, it creates a protective coating on the inside of the plant. And the soda ash wash will actually get rid of that, but if once you start taking that coating away, you can liberate out some H2S from that.
Chris Smithson:
If it was like an H2S removal unit, like our chemical injection systems, where there are real high H2S amounts in there, water washing. If it was used for gas service, water washing is good. Letting it sit in the water, the water can help to get some breakout. It will absorb some of that H2S in there. But, we’ve done it where we just take the leftover scavenger, and wash it through with that. And the scavenger will help to grab some of that H2S, it’ll kind of coat the insides of the vessel, and get in there.
Chris Smithson:
But like Jesus was saying, it’s tricky. If you start heating it up, you start putting a torch to it, to preheat, or start cutting things, you start liberating all sorts of gases out of there. If we ever have to cut on stuff, we’ve always got the sniffer out. Which is tricky, because the sniffer is only… Most of the handheld ones, they’re measuring what’s not oxygen. So, it’s not necessarily a good test to tell you. You’ve got to have the H2S monitor, four gas monitor, something that’s going to get methane.
Chris Smithson:
But yeah, it’s tricky, because as soon as you start heating things up, you can get all sorts of stuff falling out of it. And then whatever you washed it out with, let’s say you do a water wash on it, that water, if you let it sit in a tank or something, may start off gassing H2S, that it picked up if it starts heating up again. So it can be a little tricky to clean those out.
Cameron Croft:
Well, on the flanges, he was talking about flanges in particular, is there something that you wipe them down, something just before you put them in long term storage, after H2S?
Jesus Olivares:
Yeah, we probably wind up just cleaning them and then applying grease again, and putting it back. I mean, it’s like, after you doing the full wash already as it is. But we don’t do nothing in addition to that wash, other than applying grease, to make sure no corrosion is able to get back in.
Quick Tips for JT Systems
Cameron Croft:
All right. So Chris, they’re doing all the hard work. So I’m going to finally give you a question that I think pertains to you more. They wrote, “Quick tips or JT systems to operate better?” Kind of vague, but it says, “How to increase NGL recovery?” So, if you can just kind of talk about that a little bit? It seems like… Yeah, go ahead.
Chris Smithson:
I mean, JT units, I mean, it’s all about that pressure temperature relation. So you want to get as cold as you can, without dropping the pressure below the sweet spot for how you’re trying to remove it. And it depends on the JT unit, the effectiveness of it. The better the heat exchangers are, then your optimal pressure may be different than if you’re just literally going through a regulator with the separator.
Chris Smithson:
Usually the optimum pressure is going to be around like 275, 300 psi, and it gives you a big enough drop down to, and hold your cold separator at that, to give you kind of like an optimum efficiency. But really it’s temperature. And I mean once you… If you’re taking your pressure drop down to 300 psi from whatever it was, you’re going to get as cold as you can.
Chris Smithson:
The next step would be, how do you decrease the temperature coming into the system, so that you can get even colder on there, without you know increasing your pressure if that’s not an option. How you make the whole system overall get colder, without going too low on your cold separator. And really, it is finding that that sweet spot.
Chris Smithson:
Maybe it’s 250 psi in your cold separator, that gives you that extra five, 10 degrees or something that’s going to improve that recovery that you’re going to get. But really, you want to just try to get as cold, without sacrificing that cold separator pressure, because you really need that optimum efficiency in your separation.
Cameron Croft:
On that, Terry or Jesus, do you have anything to follow up on that?
Terry Nelson:
You’ve got to make sure… Yeah, and I’m back. I think actually, that was my fault. I clicked on something I shouldn’t have clicked. But yeah, and like he said, you’ve got to get that pressure drop. It’s all about inlet and outlet pressure. So, gotta be drive, we’ve got to have our methanol going. Any freezing up in the JT valve trim is going to cause a problem. So, we’ve got to make sure we have that methanol injection going across the trim, and that JT valve, keeping it clean.
Terry Nelson:
It’s really important that kind of pressure sensing mechanism you have, whether it’s a Fisher 4160, or a [Kimray 00:46:21] or whatever you have, you have to make sure it matches the kind of JT valve that you’re using. And the trim size is so important, you get too big of a trim, and it’s just gonna pop up and down, instead of holding a good 40% open, and letting that JT process happen.
Chris Smithson:
Yeah, and that is a good point. Because if you’re getting those fluctuations, then you’re not getting a real consistent temperature operation, because if it’s opening and slamming closed, and opening and slamming closed, you’re not going to get a nice consistent process for it, which is going to wear the valve out more, and cause other operational problems.
Chris Smithson:
But yeah, if you can maintain that as consistent as possible, which maybe it means getting a better pressure controller, more like a Fisher, the Norriseal knockoffs of them, instead of just the Kimray Pilot, which is super easy to use, and nice and simple, but those do have a wider band on them that they operate within, compared to the other controllers.
Chris Smithson:
One thing about NGL recovery, though, I mean, there’s only so much you can get out of it. And you’re not going to remove most of the propane until you’re below negative 20. So, some people, they’re just like, “I want C three, plus everything gone out of it.” But unless you can get super, super cold, then you’re not going to get all that stuff out of there. And you always will have a little bit of some of the heavies left in there. I mean, you can neutralize pretty much like hexane plus, but you’re still going to have some butane in there, some propane, even if you’re operating a negative 40, you’ll still have some propane in there.
Terry Nelson:
Make sure you have a throttle trim and the JT valve rather than a quick opening trim.
Chris Smithson:
Yeah.
Terry Nelson:
That’s really critical.
Chris Smithson:
Yeah, yeah. Especially on the smaller fields, because you see him a lot, they just go with a dump valve, because they’re like, “Oh, I need a one inch valve.” So, they just get the normal one inch valve that they’re used to having, and most of the time, that’s a quick open separator valve, instead of an actual throttling control valve, like they should be getting.
Chris Smithson:
And then separations [inaudible 00:48:21] pretty good too. I mean, just any separator, a lot of the fuel skids like they oversize them, because they want to have the liquid capacity to be able to take a big old slug, but if you oversize your separator, then you’re hurting your efficiency of your separation. If it’s too big of a separator, then that mist pad is not going to do what it’s supposed to, and when you’re making the gas cold, you’re creating a fog inside the gas, and a lot of it’ll start to condense immediately, it’ll collect as bigger droplets and fall out, but you need a good mist pad that’s properly sized, and that separator.
Chris Smithson:
So, oversized equipment on JT, you can lose some efficiency in what your removal is. We’ve seen that on with the simulation doesn’t predict what it should be doing, because the JT is like a 10 million JT, and they’re barely doing a million through, and it’s just the separator is just so big, that the performance is actually much worse than what it should be, because it just wasn’t sized for that. And in that particular instance, it was a Bane pack, which is a little pickier on the operating parameters for it. But yeah, knowing that the system is really operating within the conditions it’s supposed to, can improve that efficiency.
Processing LNG & CNG
Cameron Croft:
Well, two, they had a follow up question. I’m going to put it now. I guess the NGL recovery, they’re talking about LNG and CNG, what is needed to process from your experience? Dehydration? Chris and I, we’ve done a few projects on the CNG side of it, before it goes into the trucks, can you talk about that experience?
Chris Smithson:
Yeah, CNG is a little easier. The risk that you’re trying to avoid with CNG, you definitely don’t want anything corrosive going into the tanks, and then obviously ending up into whatever you’re using it for. But you don’t want any fallout in the tanks, or when you’re depressurizing from the high pressure, to low pressure with those CNG tanks.
Chris Smithson:
Typical CNG pressures are 3000 to 3600 psi. So, that’s a big pressure drop that that thing’s going to take going out of that tank. So, if that gas is too rich going in there, then you can actually get, from when you compress it up, if the compressor does another right after coolers, and separators, you can actually end up with liquid in those tanks, which would just defeat your capacity of the tanks if too much of it builds up.
Chris Smithson:
Same thing goes with the dehydration, if you’re not dehyd going into that compressor, when that compressor gets you up to 3600 psi, that gas at that pressure can’t hold that much water anymore. So, you’re going to have water fall out, and the compressor is not separating it like it’s supposed to, then that ends up in those tanks. And then if it ends up depressurizing into… The depressurize, like usually it’s a heater, that they depressurize through. If that water hits that, then you’ll just get a hydrate, and freeze up the whole thing. So, it is important. Usually pipeline spec is good enough for CNG. So if your equipments getting it to pipeline spec, then it is good enough to put into a CNG process.
Chris Smithson:
LNG is a different thing. LNG, you’ve got to get all the CO2 out, because the same way we have problems with… The reason we dehy, to not have hydrates, with LNG, you’ll have, CO2 will turn to solid. You’ll get dry ice chunks in it, because of the temperatures the LNG is operating at. LNG has to be very, very clean gas. Basically eliminated all the CO2, and you’re talking like 98% methane, with hardly any ethane left in it as well.
Cameron Croft:
Is there any anything you want to add to that, Jesus, or Terry? Because we have time for one more question. Okay. All right. So, this is a big one. But, Terry, this is for you. This is… Or if you could take the lead on this one. This says, “We are moving in the old TG unit to a new field that has very rich gas. Is there anything that needs to be added, or changed on it, to make it work? The unit a standard handover.” Which you should have experience on that. “Handover unit, but the field it was in had very lean gas, and the operator is concerned that the different gas will change how it operates?”
Terry Nelson:
That’s a good question. It actually shows that you’re thinking ahead of time, you’re moving this unit, and you’re aware that there could be some issues. The first thing is the unit was designed to operate at saturated conditions. So, no matter what the condition is now, or what it will be, water wise, you’re going to be fine.
Terry Nelson:
Now, when you’re talking about rich gas versus lean gas, that’s when we’re going to get into possibly pre treating, to remove NGLS from the stream, to lower that BTU of gas before it gets to the dehy, and that’s where guys at Croft could put something in front of it, like a JT skid, or something to manage the BTU.
Terry Nelson:
Now, when you look at the dehy itself, the first thing I’m going to do is clean it. Because you don’t want to carry your contaminated issues to the new location, because when you lay that tower down, and put it on a truck, and you stand it back up on the new location, you’re going to have a lot of organics, and solids, and stuff break loose from the vessel walls, and in the tray and packing, and the fire tubes and stuff. You’re going to have a lot of solids that are going to plug the whole system up when you start it back up.
Terry Nelson:
So, personally I would want to chemically clean it, and clean everything, and then drain it, make it ready. You also have to DoT regulations you’ve got to follow, you’re hauling pieces of equipment down the highway you don’t want glycol, and hydrocarbons coming out of it. So you want to clean it, and flush it before you ship it.
Terry Nelson:
If you have really rich gas, you want to make sure… I know a lot of the old handover units, the older ones did not have charcoal filtration, or charcoal absorption on them. I would want to add a charcoal canister to that skid, like an 1122 charcoal canister, so that when that glycol picks up those hydrocarbons into contact tower, because now you got richer gas, it’s going to be saturated not with just water, but it’s going to have a lot of hydrocarbons in it. You don’t want that getting in your reboiler. That puts a lot of load on your B tech system downstream.
Terry Nelson:
So, that’s all that counts for emissions. So you’ve got to make sure your pump gas separator is working properly. In your lane gas application, you probably didn’t make a lot of hydrocarbons in your flash gas separator, or your pump gas separator. In a handover unit, I don’t know what size this is, smaller one, it has a little separator that sits on top. Or it could be a vertical vessel off to the side, with the bottom insulated.
Terry Nelson:
That has 10 different names, but it’s just a three phase, low pressure, separator, separating glycol, hydrocarbons and gas. So, there’s only two places that are in the system of the regeneration unit, the glycol system, that’s designed to remove hydrocarbons. That’s the pump [inaudible 00:55:51], and the charcoal [inaudible 00:55:54].
Terry Nelson:
So, when the glycol dumps out of the three phase pump gas separator, going back to the reboiler, it normally needs to go through a charcoal canister, to absorb what’s left, and train in the glycol. So when the receives the glycol, all it has to do is flash off the water. Remove all the filters. Before you shut the system down, test both pumps, to see if they work. Because one of them, if it’s a standby pump, probably got switched over to the good pump, and the first one was never repaired. So, just going by historical data here, guys. If it ain’t broke, don’t fix it. Crash mentality we’re in right now. So, test both pumps and see if they work. If not, then you know, because the guys that are receiving that unit.
Cameron Croft:
Terry, we lost you. But Jesus, Chris, did y’all have anything to add to that?
Chris Smithson:
Yeah, two big things on different ends of the glycol unit, that I would say. And I know Terry definitely pushes it real hard, as his inlet separation has got to be real good.
Chris Smithson:
Inlet separation is super important. If it’s rich gas, I’d say you basically need to have a coalescing filter ahead of it. The inlet knockouts, it’s on a contact tower, they’re, in a lean gap application, like where this thing sounds like it’s coming from, that thing probably never caught any liquid. But for rich gas, I mean, a good coalescing filter, preferably reverse flow, sub micron, like a real coalescing filter, not just a filter separator, I think you just really needed to have that ahead of that unit, just to make sure. And maybe a separator before that, just if there is liquids that are going to be slugging into it.
Chris Smithson:
And then the other thing is, on the other end of the unit, if they have a B Tex unit, if it’s got the kind that reinjects the gas into the burner, the operator better know what he’s doing with that, because I’m sure Terry’s got tons of stories of those things catching fire, and it’s always rich gas applications where the hydrocarbons are made and where the reboiler and then overflowed into the B tex, and shot back into the fire tube, and then shooting flaming gasoline everywhere.
Terry Nelson:
I really had some brilliant points are right at the end, too. Just so everybody knows.
Chris Smithson:
But yeah, I mean, I think, if you have to have a B tex, and it’s really rich gas, I would look at maybe putting a separate combustor, or running that gas to not the burner on the glycol unit, because that’s a big risk, a fire hazard to do that.
Conclusion
Cameron Croft:
Well that’s the end of our questions right now. So, what I want to do is, it’s been an hour, but we’re going to wrap it up. If you’re interested in being a webinar speaker, or know someone who wants to be, is a good fit, please reach out to us, let us know. So that way we can touch base with them. The whole purpose of this exercise is to the shared knowledge to talk to the subject matter experts, what’s going on.
Cameron Croft:
You will be getting a survey. This is our first round table so we’re really… Everyone that’s on this call, on this webinar, we’re really looking for y’alls advice on how can we make it better, longer, shorter, more pointed questions. “I only want to hear about glycol systems,” Please just let us know about what you’re wanting to go through. We’re gonna make this a monthly round table discussion to only focus on questions. So if you have any questions outside of it, reach out to us. If you have any particular questions, please let us know, so that we can get it prepared for the next time that we hold this thing. So, I’m going to stop sharing. But, Jesus, Chris, and, Terry, thank you all so much for taking the time. Y’all have devoted a lot of time to this, and I appreciate your effort in doing this.
Jesus Olivares:
You’re welcome. I think, overall it went pretty well. I think having those pre loaded questions helps to probably get a little bit more into detail. But, overall, I think it was good.
Cameron Croft:
Yeah, that’s one thing we’re trying to do, is how do we increase engagement? We really want… Thank you to the participants on it, we’re asking the live questions as we were going along. This is y’alls time. So, any pointed questions, we’re here for you. But, we’re going to make this a monthly basis, and then we’re going to be shipping out invites to y’all, reaching out to you personally. So, we’re going to wrap this up guys, and if any of y’all have anything left?
Terry Nelson:
Really, I appreciate it.
Cameron Croft:
Absolutely. All right, y’all take care, and thank y’all for everything. Bye.
Jesus Olivares:
Thank you, Cameron.
Conclusion/ Q&A
Cameron Croft:
Well, that ends the case studies. So quickly we, got a Q&A section at the end, but we do have an upcoming webinar that’s coming. It’s a production and processing round table. So I am really excited about this. We’re actually having Chris come back. We’re having Terry Nelson with Waukesha-Pearce, speaking with us, and then we have Jesie Olivares with Osynergy. This one is going to be a little bit different. We’re opening up the platform. Anyone can ask any questions about processing, filters, JTs, dehydration, anything going in the line. And then now we’ve got these three subject matter experts that will be giving their best recommendations. We’ll have some reference materials. But we’re really opening it up to anyone that can ask these type of questions. So that’s in two weeks. If you’ve got some pre-questions, you can’t attend, but you have some questions, just submit it to us. So that way we can make sure that those are addressed to these three subject matter experts.
Cameron Croft:
Now, if you’re interested in being a webinar speaker, or if you know of someone, please let us know. We want to each out to [email protected]. So that way we can get them coming on board, sharing that knowledge. You will get a survey at the end of this. Again, I’m Black Belt Six Sigma, so I love continuous improvement. I love data. So the only way we can get better is actually by y’all filling out the survey. From the last survey, it actually helped us a lot. People wanted more open platform questions, and that’s why we came up with a round table discussion, just opening up to just answering questions. And I think that’s going to go over very well.
Cameron Croft:
So the Q&A section right now, we did have a couple of questions through the presentation. I don’t see any new ones right now. But again, if you don’t have them now, you get them back out to your field. One of our other companies we have is Croft Supplies. It’s an online eCommerce. You can order all the filters through there. If you have any particular questions, things that are happening, please reach out to us. We’re here for you. We’ll let you know about our best recommendations of chemical compatibility, what might work. Or if anything, we can just probably spitball some ideas for you. So I don’t see any questions. So we’re going to end this webinar. But again, reach out to us, if you have any questions specifically about your projects’ equipment that you’re dealing with right now. But I appreciate it. All right. Thank you guys. All right. Let’s go to lunch, right?
