Introduction
Cameron Croft:
If you’re just now joining us this, is our H2S and CO2 Removal Virtual Roundtable. This is us focusing on specifically getting subject matter experts coming together, talking about true applications, past experiences on focusing on H2S and CO2 removal. So some quick housekeeping, if something happens, this is on the internet, if you lose connection, kid walks in the room, internet goes out for some reason. We will be putting this on our YouTube channel and a transcript so that way you can do a quick control search on YouTube, LinkedIn, blogs, that we have all of our information on.
Cameron Croft:
I’m Chief Executive Officer at Croft Production Systems, we’re a natural gas processing company. That’s what we focus on. I have my Director of Engineering joining us with Croft Production Systems, Chris Smithson, he has a lot of years of experience focusing on production and processing of natural gas. Jesus Olivares is joining us. He has a lot of experience in the back end design work even in civil projects but in oil and gas projects. And then now he’s a CEO of his own manufacturing facility, Osynergy. And we have Terry Nelson, who manages WPIs division focusing on dehydration, natural gas processing issues, JT plans. He’s going to be joining us today. He has a lot of experience back Hanover, Exterran.
Cameron Croft:
So from these subject matter experts that we have joining us today, we’re going to be focusing specifically for H2S and CO2 removal. So today’s outline quick, H2S removal, CO2 removal, and that we do have a good case study at the end, kind of a focus that came from one of our people joining us today, he’s from Australia. Now, the round table structure, how this is going to work because not everyone can answer. So I’m going to be playing the host, I do have the question and answer, and the chat function up and running. So if in our conversation, if something comes in your mind of having a quick question, or if you want confirmation on something, put it in the question and answer, or you can put it in the chat function, and then as soon as it comes back up, I’ll make sure that question is trying to be answered as best of the ability as we can give it.
Cameron Croft:
So kicking this off, we’re going to be focusing on natural gas contaminants, specifically, again, for H2S and CO2. Starting this conversation off, what we did is, I want to quickly touch bases on the processes for acid gas removal. We only have one hour, but the first one is a batch process, then we’re going to go into continuous injection and then the third is the regenerative process. So in this, kicking it off is the batch process. Now the functionality of this, Chris, I meant if you can kick us off with the batch process. You got bubble towers, solvent treat kind of go into your experience on that.
Batch Process for H2S and CO2 Removal
Chris Smithson:
Yeah, so the main batch process is either a solid or liquid that’s going to remove the H2S or CO2. Molecular sieve is technically a batch process, regenerative but it’s technically a batch process, and usually, you see that on big facilities for fine-tuning CO2 and H2S removal. Solvent treat is a big one for it, it’s the solid black material that’s shown there. They also have, they’re made in different formulations, they even have one that looks more like those beads but the solvent treat is CO2 removal, it also does other sulfur removals for different grades of iron oxide, iron oxide type media. Solvent treat is just a trade name for one brand of products.
Chris Smithson:
The other batch process you see a lot in the field is bubble towers filled with liquid scavengers, the H2S scavenger that’s spilled up there, and it’s just operated until it doesn’t meet spec anymore and it’s drained and refilled. So those are the main batch processes you see out there for H2O and CO2.
Bubble Towers
Cameron Croft:
So to be a little bit more specific, let’s focus on bubble towers, what are the past experiences on bubble towers, especially like personnel issues?
Chris Smithson:
So for bubble towers, I mean, they do have a good fit for smaller well volumes where you’re not going to be consuming that scavenger, inconsumable scavenger eventually you get to throw it out. So the longer that’s going to last between having to refill that bubble tower is important. So smaller well volumes that aren’t going to use up that scavenger or lower H2S levels, something in the H2S range of maybe less than 100 PBM on volumes, less than a million that’s a good range for a bubble tower. I wouldn’t want to refill them more than once a month. They can get kind of tedious if you have a chemical guy going out there every week, trying to refill them. But there can be higher H2S removals, you can definitely have some problems with the scavenger building up in there.
Chris Smithson:
And I’m sure Terry has had some experiences with seeing what that scavenger can do when it goes bad and you end up with those solids in them.
Terry Nelson:
Yeah. The problems with the batch, I mean, it’s an excellent tool for, like you said, lower in process ranges where you have a minimal gas flow and your contamination levels not so high. But the problem seems to be that one is getting rid of the batch product and having to either dispose of it and then of course, financially keep replacing it. And secondly, and what I find is when people, don’t have the forethought to make sure that everything attached to that vessel and in the line after it can handle the corrosiveness of what we’re dealing with.
Terry Nelson:
I’ve had customers where they repurposed vessels as just a separator, so let’s fill it with some stuff and let the gas flow through it when they don’t think about corrosion allowances, and making sure that all the controls and instrumentation, including relief valves and everything else, are meeting the standards of what the product is now that you’re dealing with.
Chris Smithson:
Yeah, fit for purpose vessel can be a lot better. Yeah, we’ve seen some interesting retrofits. Jesse, I don’t know if you’ve ever retrofitted vessels for bubble towers?
Jesus Olivares:
Oh, I had. I think one of the things that Terry was mentioning that you have issues with is, especially if you don’t go through the proper cleaning process of getting rid of your old stuff and it starts coking and then that coke can start eating into your vessel and your material and before you know it … I mean, if it just there a month longer than it should for example, then it can start eating up and an estimate costs a lot of money to replace stuff, and then you got issues. But just trying to modify something, I’m one of those in favor of saving money and if you’re able to do it correctly, then yes. But basically, you have to take something that was used for a different process and you have to get it out and repurpose it correctly into what you need now.
Jesus Olivares:
So I think that that would be the key that if you’re going to repurpose something, make sure that you do it completely not just, I’ve seen it work. You got to have like, it was in two trays and got converted, but they didn’t remove the tray rings. They removed the trays but not the ring so all that was just creating a big-time corrosion point. So I think it’s just when you do that, make sure that you do it completely, not just half.
Chris Smithson:
Yeah, we saw one vessel that was a converted molecular sieve vessel, and molecular sieve, which is those little tan-colored beads, they flow really easily out of a vessel. So I think it was like an eight-inch port or something, which is fine for molecular sieve, but trying to get that solvent treat, the standard solvent treat isn’t uniform in shape, it’s like little crumbles. And trying to get that out of those tiny little ports makes clean out rather difficult. These other brands are an oxide that is around and they flow out better. They don’t clump or turn into concrete-like some of the issues you can have sometimes with some of those self treat options. But yeah, that can be problematic.
Chris Smithson:
And then even the bubble towers running scavenger, if you don’t have the right drains on them, maybe bigger drains, maybe some clean out boards, we’ve seen that solidification it’s when you overuse the scavenger, you get this yellow caky material. You get two different types of by-product from overusing scavenger, you get a soft squishy material, it’s like cottage cheese. Or you get a very, very hard crystal material. The soft material can be melted out, you run into like … We’ll do hot water baths on our injection systems and that’ll melt the sulfur out, run 200-degree water through it. But that crystalline material, the only way to get that out is mechanical, a lot of acids won’t even really get it. So that’s really problematic if you got just a little one-inch drain on one of those vessels and you’re having clogging issues, that’s going to give you a headache every time you try to empty that vessel out.
Jesus Olivares:
I was going to say, it just reminds me of when you’re trying to clean some of these vessels and they’re already all kicked up, right, that you almost have to sandblast that thing just to get rid of all of that. So, yeah, it’s a lot of work to go after it’s already all caked up and then you’re having to clean it. We’ve had to basically sandblast in the last step just to get it rolling faster. Sometimes we try to put some of these jet systems in there to try to get the circulation going, but the bottom line is that you follow the right operating procedures and you have a good maintenance procedure, you should be able to avoid all those things.
Cameron Croft:
Well, that kind of leads to one of the questions that we did receive. What are some quick tips for bubble towers? Is there any like quick retrofit or something that you all can go in, diagnose what they should add to the system just to make their operational lives easier?
Chris Smithson:
For a bubble tower, if you’re using liquid scavenger for a bubble tower, if you’re having issues where it’s getting used up and you’re seeing that precipitate come out of it and you’re getting that clogging issue, you’re probably also refilling that vessel a lo and more often than you’d probably want to. I would say put some direct injection ahead of the system, try to get rid of some of that H2S, I mean, you’re going to spend what you’re going to spend on a scavenger. You save money when you use it up so much that it creates that solid, but the solid is going to be, it’s not worth the savings that have that much of a headache. But I would say, try to get some scavenger ahead of it and separate it out.
Chris Smithson:
That way the bubble tower is not working so hard and you’re not having to clean it out as much or refill it as much. And then solvent treat, I mean, do the same thing with the solvent treat if you’re really annoyed with how often you’re filling it out or refilling it. You can try to maybe do something ahead of it and try to knock down the usage on that. Iron oxide is the cheapest way, pound for pound cost is the cheapest way to remove H2S, it’s just can be a big headache to refill those things.
Terry Nelson:
Yeah, I agree with all that. I tell people, and it was mentioned earlier, do not let the stuff stay in there past its life. All these things have a lifespan, once the efficiency of what they’re there to do has run its course change that stuff out, don’t for economics or whatever, let it linger in that vessel longer than its efficiency maintains. Because what you’re doing is, that product is going to start solidifying and bridging over in that vessel and it’s going to be really tough to get it out. The longer you leave it in their past its point of efficiency, the harder it’s going to change it out. Another thing is, for the crews that go out and work on this stuff, and that’s what our guys do is just because you’ve removed the product out of it and just because you stopped the gas flow going through, it does not mean that you’ve eliminated the H2S in that vessel.
Terry Nelson:
That metal is very porous. The inside of the vessel will hold a lot of that H2S, you hit that with some hot water, and when you’re going through the cleaning process, you’re going to release H2S and it’s a definite hazard. So you have to make sure that all the PPE is followed, even if you’re just pointing it out. And the third one is, any liquid grain lines that lead these vessels that go to a slop tank or to the storage, in my humble opinion should be an independent drain line. If they’re tied in multiple sources, that product can migrate back through those dump lines and cost plugging that will cause the other vessels to blow cases that are trying to get rid of their product. It can cause a restriction in those lines, and then you’ll spend days trying to trace it back and figure out what’s causing the limiting of the other dumps from going through the drain lines.
Chris Smithson:
Well, yeah, we’ve definitely have seen that where we get like a backlog of, it’ll shoot off the solids down like a seldom-used drain line. And then all of a sudden that separator tries to dump but it can’t dump anymore and break a dump valve off. And somehow you have solids all the way back up to your trim of a dump valve that shouldn’t be seeing any scavenger on the front side of it.
Do you recommend any additives to the triazine in H2S scavenger to minimize solid precipitation from the spin chemical?
Cameron Croft:
We do have a question, Shane asked, do you recommend any additives to the triazine in H2S scavenger to minimize solid precipitation from the spin chemical?
Chris Smithson:
I’m not a chemical guy, I’ve just talked to enough to know that I’d hate to be a chemical guy. So triazine is only, two or three companies actually make triazine like the base product, everybody else, they buy it from the same people. So the base triazine product or the way that works is, it’s a chemical compound. It can grab up to three H2S molecules. When you grab the third one though, there’s a chance that it breaks off from the molecule and you get the sulfur actually is a free compound floating around where it can collect with the other sulfur and create the solid. So if you have the solids in there, it means that you’re using it up completely, you’re just living with that by-product of, being that effective at what it can do.
Chris Smithson:
The only thing that I’ve seen, I mean, most people blend them with like a scale inhibitor and a corrosion inhibitor or it normally has a corrosion inhibitor on its own scavenger, but I bought a scale inhibitor to keep any sort of scaling from forming in the pipe. But methanol is the only thing that I’ve heard … We had a bunch of problems with this when we were first getting in our chemical skids years ago, and we saw a lot of the solids buildup. It does seem to depend on the scavenger certain ones, are more likely to have that buildup. We used to use one that smelled terrible before you even used it up, and that one for some reason really had a bad problem with the solid builds up. For the normal triazine, we use a fairly standard blend of triazine but adding methanol to it can help to keep the solids from forming.
Chris Smithson:
I read that in a research paper and I’ve heard that from one or two chemical guys, but it can take a lot of methanol. I don’t know if it will completely stop it from happening, but it is a pretty good idea to just have methanol mixed in there all the time, not just for winter to keep it from freezing.
Cameron Croft:
Didn’t we, Chris, this is where that South Texas project, where it started getting, that solidification started happening. Didn’t we lower the concentration of the triazine as well, just to make sure there are enough fluids that when it was dumping it was properly dumping and cleaning it up?
Chris Smithson:
Yeah. We normally would use like a 50/50 mix, so it’s 50% water, 50% active chemical in our units because we’re trying to treat within a skid unit. Direct injection, pipeline injection, and the typical blend is a 25% active to 75% water. And so yeah, in that case, we did go to the higher water mix just to keep enough fluid going through there. We had to double our injection rates with the chemicals, almost half the price, they’re going to sell you water somehow. So that helped to just flush things out just because we’re physically moving more liquid and helped to push more of the solids away. So yeah, that did help to go to that, and we had to add an extra pump and more batteries, more panels to power it, but it did help to keep that clogging down.
Terry Nelson:
Well, flushing is the right term, and that’s why I mentioned earlier to have a dedicated dump line on this kind of stuff. But also, what I’ve done is when it leaves a vessel and enters the line going wherever it’s going for disposal or whatever, add a connection there where you can flush it occasionally. And have a part of your PM process on a regular basis to either don’t mess them all into it or something, whether it’s water, whether it’s maybe tying off of another dump line and allowing that to blow through there occasionally just to flush that line so you don’t get that build up. Because over time, the product we have to remember, we’re pulling sulfur so you’re going to get some caking or solids in that line. So if you flush it occasionally that helps keep that stuff from building up and bridging inside that piping.
Cameron Croft:
Well, that kind of goes into, we did have one, I think it applies mostly to this one, but they were having trace amounts of H2S before it hit their instrumentation and fuel gas. And they were just wanting a quick cleanup or even a redundant vessel. What do you all find is the best way to treat for that trace amounts of fuel gas and instrumentation gas before it goes into those lines? Is that a bubble tower or a …
Chris Smithson:
Yeah, I think a batch process would work best for that. Usually that’s intermittent volumes, anyway in batch processes are usually a little better at that. Continuous you may end up wasting a little more chemical. But yeah, I mean, solvent treat is nice or iron oxide is nice for intermittent flows and where it gets … Bearing volumes because you’re only going to use as much as there is H2S in there. Bubble tower could be good for that as well but like Terry said, I mean, eventually if it sits there for a long time, bubble towers will pick up other stuff, the solvent treat will too, it’ll pick up the other stuff. So you may end up having to clean it out before it really is time to do it just because it’s been in there for a year and a half.
Chris Smithson:
And if you don’t do it now, you’re never going to be able to. I would go with the batch process on that because that’s smaller volumes like that you’re not, you had to put a vessel out there anyway. So it’s going a little bit bigger on the vessel, it’s not that much more of a cost to have a little overkill in there.
Terry Nelson:
Well, like on the offshore platforms that we maintain through the years, we would have an issue where on some of the platforms you would have a minimal amount of H2S and we had to worry about it with instrumentation and animals and contaminating all that. And we would put a batch vessel there with like the beads in it depending on the product, it’s different. And then that way it was easy to transport for waste disposal when we had to change them out, and it was also, they’d last a long time and you’re only talking about a very small contamination level and very small amount of gas when you’re talking about something on the inlet for controls and stuff like that. So it works really well using a batch.
Jesus Olivares:
Well, especially if you do twin set up where you always have one as a backup, you switch over, you could have one of them and operate the other one so you’re never shut down. Another idea obviously is, you’re able to evaluate your design and what are you able to do the nitrogen little setup or something else, I think, would eventually know how to use your natural gas. So just looking at what would be more cost-effective and what’s more available at that time, but since everything changes, what might or might not have been a good idea at the beginning down the road you might reevaluate and go with a different option.
How do you quantify amounts of H2S?
Cameron Croft:
Well, we got another question that popped up, it says, can Terry qualify minimum amounts of the H2S?
Terry Nelson:
No. Well, I mean, I think that Chris mentioned that earlier when we were talking about what we consider minimal amounts of H2S.
Chris Smithson:
Yeah, I would say, really you’d want it to be something around like maybe 50 PPM. It depends on the volume, the volume in H2S is going to determine how much product you’re going to go through. I mean, you may be 1,000 PPM, but only all you need is an MCF, and so at that rate, it’s a lot of H2S but if that gets you like a two-month refill cycle, then you’re pretty good. But if it’s like 10 PPM, and we were doing one application that was 12 PPM but it was 30 million a day. So we were like 60 gallons of scavenger a day that we were using. So it depends on what that crossover is as far as what the usage is. Obviously don’t want a tremendously large batch vessel just for 100 MCF a day in fuel or something but it would depend on what that H2S rate is.
Terry Nelson:
And what’s the CO2 level? And is it dry? Is there any moisture? I mean, you could have a very minimal amount of H2S, but if you have moisture that changes everything, so have to make sure that that is very dry fuel or very dry gas.
Chris Smithson:
It also affects what you’re going to use too. So if the gas is already dry, but it’s got some H2S in it, if you put a bubble tower out there that’s half water, then you’re just going to re-saturate the gas and now your instrumentation gas is wet again.
Terry Nelson:
Exactly.
Chris Smithson:
Then you got to put out like a little batch PDS vessel or something to dry it out, and then you’re adding other problems. Because iron oxide are the ones that don’t need wet gas, a lot of them do. I think most of the standard solvent treat product needs water in the gas to work properly. You can’t really run dry gas, they have special blends for it. But yeah, it can affect what your, that, “Oh, let me just add a little bubble tower here and it’ll be fine.” And then all of a sudden you’re having other problems.
What are some other liquid H2S scavengers used for contact towers? How did it compare it to triazine efficiency, economics treatment issues?
Cameron Croft:
Well, we did get a question coming up. I think it’s going into the more the regenerative process. I’m going to scroll down, but it’s saying, what are some other liquid H2S scavengers used for contact towers? How did it compare it to triazine efficiency, economics treatment issues?
Chris Smithson:
So that’d be for the direct injection or the CIS unit. So like some set of triazine, what other options are there? So triazine is the most popular. I don’t know how they quantify that, I mean, all the different people that use it all over the world and everything, but they say triazine is the most used consumable scavenger that there is. There’s other ones, Baker makes a couple of different products but they have an amine based. There’s one that has formaldehyde in it. I just know that because it smells terrible but it’s not a triazine based, it’s a converted amine that ends up with formaldehyde in there for some reason. Those aren’t as effective as triazine, I think triazine has kind of won that battle as far as usage for that.
Chris Smithson:
The converted amine ones also, they can have more issues with the solids as well. There’s other types out that are iron based, like a liquid that has a bunch of iron oxide in it. They can actually be regenerated or it can just be thrown away as a scavenger. It’s a little pricier, but it’s not triazine. I know some pipeline companies have issues with triazine, I can’t remember offhand who it was, but we were working on an application where the pipeline company didn’t want the triazine. Something to do with corrosion, I wasn’t exactly sure what the reason for that rule was. But there’s a couple other options, triazine is just so common that it’s hard to compete on price for anything else.
Bubble Tower Designs
Cameron Croft:
Well, hopefully, that answered Shane’s question, but you were talking about continuous injection like into the tower. We’ve seen Polaris, Exterran and Hanover designs. We’ve got several bubble towers that we ran out of. What is y’all’s experience on that, where it’s just liquid on the bottom? We’ve seen them where they atomize at the top, have you all seen the efficiency gains in the atomization at the top, and then having it just settle out in a liquid on the bottom of … What design do you all like the most?
Terry Nelson:
I mean, I think they each have their own benefits, but the atomization at the top, I mean, that has benefits that to me be more efficient. But then some people tell you that the bubbling from the bottom is better, but I think it’s just dependent on the chemical you’re using and the overall rate of contamination, and how much you have to treat to get out.
Chris Smithson:
Yeah, the Volaris design bubble towers, they atomize in the top, and then they have the accumulation bubbling section on the bottom. They had a recommendation of like 2000 PPM max, and I think part of that there shouldn’t be a nice function, Jesse would know better. I mean, I’m sure they could design it to handle higher H2S amounts but they, I think that Max was really more stemming from having to just inject so much scavenger into it, that it’s not really feasible to go higher as far as that. What’s pictured here is our little CIS 100, it’s for 100 MCF a day. We’ve actually treated 10,000 PPM with this, which is a percent of H2S for a fuel gas application for a generator. And I wouldn’t say it’s cost-effective against diesel, especially with diesel prices now, but back when diesel was more expensive, it was at that rate at that 10,000 PPM.
Chris Smithson:
What this unit is, it’s got an atomization injection, that’s got a static mixer, and then we have the bubble tower that’s really more of a separator and finishing in it. Bubble towers are great at smaller volumes, I just wouldn’t try to treat 1000 or 2000 PPM through just a bubble tower, just because it doesn’t have enough contact time. The Blair’s design ones have the atomizers on the top, so it’s constantly the freshest chemical in the top. And then it’s going down to the spin chemical, so they do use it up a lot, but the real high H2S rates you’re not really going to want something that’s just churning in there because you really need to start getting that scavenger out of there, or else you can have some problems with it. The UltraFab units are a little different. The UltraFab units have, they’re running it through a contactor system. So they have like a packed tower and they’re running it through that tower, but it’s the same problem.
Chris Smithson:
Real high H2S rates you can end up with a clog. I’ve heard horror stories from techs talking about trying to clean out those UltraFab units where they just get completely full sulfur, but that can happen on any bubble tower system.
Terry Nelson:
The biggest problem is when there is a misapplication when you use a vessel that was designed for a certain application, a minimum contamination rate or minimum flow rate, and you put it in an application that doesn’t meet what it was designed for, it’s never going to end up well. Because you end up with a vessel that you either have to change out the product more often than you should or you get the plugging and you have all kinds of problems because it wasn’t designed for the application that it’s put into.
Cameron Croft:
Well, like you were saying, Terry, on our first design of this chemical injection scale, we had started building the bubble towers. Well, we had the drain port and the level controller approval set kind of at the bottom where you were at first draining out from the bottom. And what we were finding out, there was so much condensate that was coming in, so the condensate would start filling it up. And it was practically just kind of like, it was floating on top of the scavenger so it was pushing out. So we were actually draining out the scavenger so by the time … A few weeks went by, our thing was full of condensate, but it wasn’t full of scavenger anymore. So then we started draining at a higher port, so that would trigger from that and we were approved with draining off the condensate off top. So there’s a lot of quick tricks that, yeah, it has to be applied to it.
Terry Nelson:
This goes back to the point of when people are repurposing vessels and just taking a separator and put it on a scale and adapting it for a bubble processor that the connections are not going to be in the right place, so there’s a learning process.
Cameron Croft:
But Jesse, you don’t have to have any of that with your customers repurposing, right?
Jesus Olivares:
Well, and I think we’ve had a similar conversation in other of the webinars who’ve had, and it goes back to understanding, and Terry brought some of that up in this webinar and so forth. Understanding the conditions, especially skid packages, it’s so easy to move them from one place to another that you’ve seen that, oh, if it worked here it’s going to work over there. Well, that’s not the case, you need to really understand the conditions because … I mean, you might have the same gas flow but what if you have a different lid with different component composition, all those sorts of things that if you don’t reevaluate that you’re going to end up having issues no matter how good the equipment was.
Cameron Croft:
We got a question for a contact tower, but I’m going to leave that for the regenerative process towards the end. But I kind of fall back onto my dad, he was an operator, consultant operator who was on a bunch of fields. One of the biggest things that he saw on the expenses was the chemical usage on the location so when he started consulting out there he started documenting. Chemical salesman, they get a bad rap because they’re water salesman, everyone keeps popping on that and you get good chemical sales people that honestly want to do a good job but if you don’t give them the right data, they don’t know how to respond with the right chemical.
Cameron Croft:
So my dad started focusing on that and what he found out, his client was doing just drip injection, continuous injection, that was just drip injection. They were using all the 90s and 180s and coming back and trying to make contact time. So he took those out and just put atomization in there. And what he claims, now it’s my father, he tends to lie to me a lot, but he said, he claimed that there was a 20 to 30% drop in chemical usage just by putting the atomizers and people were getting better contact time rather than relying on drip injection.
Terry Nelson:
That depends on, if you’re buying the chemical or you’re selling the chemical.
Cameron Croft:
Right. Yeah, it could be that too, right? Well, I mean, was there quick tips that you all have seen in the past that some … I mean, operators are resourceful, so is there anything that you all saw that was a cool, best standard practice?
Terry Nelson:
It’s all about, it’s atomization, no doubt, but it’s where you do it. You have to find an injection point with a certain amount of straight pot so that you can get the mix going. And the atomization has to occur down a straight piece of pipe, if you have too many 90s and stuff in a connection that links the pipe with too many bends in turns, that’s not the place you want to inject it because you’re not going to get a good mix. That atomization is going to be spoiled because of all the twists and turns, you have to atomize it at a point where you get the benefit of a straight piece of pipe. That’s just the tip that I have done in the past I find that works well.
Chris Smithson:
Yeah, I think that’s true because an elbow will knock out a lot of chemicals. Like a lot of it when the sheer stresses the gas going through there just throw out the atomized stuff. So yeah, Terry’s right on, you don’t want to inject right before a bunch of elbows. You want that nice long run where that fog that you created can go through there. That’s another tip, there’s difference between a mister and a fogger tip for atomization, you want an atomization tip that’s really making real tiny droplets because you’re getting more surface area that way. You don’t want something that’s just going to mist in there and like big, old, heavy droplets that are going to fall out real quick. The finer tip that you can put on there, the better, which means you got to filter good your chemical or else you’ll clog up the tips a lot sooner.
Chris Smithson:
But the other thing is, is going to do its job. It’s going to remove the H2S, it’s going to fall out eventually. So you do want to separate or downstream of that, but you don’t necessarily want that separator too close. If that mist that you’ve created is getting knocked out in your separator, that’s good, you want that to happen. But if you have a mist pad and not a vein pack in that separator and that scavenger is building up in that mist pad, collecting and then dripping back down, you may have your solids problem occur in that mist pad. So now you have a mist pad it’s full of sulfur solids in there, whereas if you’d given it more pipe run and then maybe hit that area with all those elbows where that’s getting knocked out after it’s done its job, then you’re having more of a free liquid hit that separator and hopefully it’s not getting stuck in the mist pad because we’ve had that on units.
Chris Smithson:
That was our mistake when we first started building those CIS units was put mist pads in because it makes them a lot harder to clean when you’re trying to get a curved sheet out of a bundle of stainless mesh.
Jesus Olivares:
I guess the mist pad was doing its job, wasn’t it? It was basically coalescing.
Chris Smithson:
Yeah, I mean, it works too. It’s giving you a service area, the liquids totally coated it. So it’s lit and it’s over H2S out, but when it came time to clean it and it makes a much bigger problem. If you ever see a differential on something like that, I mean, the differential is most likely in the mist pad. If you’re injecting scavenger and you’re having that problem, that’s the first place because that’s the tightest place on the whole thing. So we’ve seen that on sites where they’re injecting scavenger and they have 15 PSI differential across their separator, and that’s really a red flag because you’re seeing that.
Treating H2S at the Head of a Tank
Cameron Croft:
Well, that goes into, before we move on to the regenerative process, there was one, they didn’t mention other water storage or oil tanks, but they were saying that there was H2S being liberated in the head of the tank at the top of the tank. So they were trying to figure out, they didn’t mention a vapor recovery unit or anything, but how would you all go about treating for H2S that’s at the head of the tank?
Chris Smithson:
So I think a cool trick that we saw from our local chemical guy was that they were atomizing into the head of the tanks. I thought it was neat, they just took out a bolt out of the thief hatch flange bolts, they took out one bolt, put a bulkhead tubing fitting, and then they put the atomizer in on the inside of the tank. So you could really easily change the tip if you needed to, but they were knocking down a couple of thousand PPM of H2S just by fogging that headspace of the tanks, which makes it so much safer for the guys that actually had to pull a gauge on those tanks. They’re opening up a thief hatch with 1000 PPM, because it will concentrate in areas like that, especially in the heat of the summer, it’ll liberate at oils or gases.
Chris Smithson:
H2S is kind of weird, you could have oil without really any H2S and gas full of it. Or you could have gas with a little H2S and then really high H2S levels in your oil, and you would need two different scavengers to properly treat those two different strains because the oil scavengers and the gas scavengers don’t quite work as well interchangeably. But yeah, treating that, just that gas headspace can be pretty effective.
Terry Nelson:
What we’ve done is, that’s always an excellent idea to have that misting right there at the thief hatch. What we’ve also done is, on the piping of the tanks as it enters the top of the tanks, we’ve put a tube there before with a valve and piping away from the tank so that when an operator goes up to have to gauge or whatever, he can vench, manually vench before he pops the thief. And then he’s blowing that high concentration out away from him, then he can relieve that thief hatch pressure, which is basically already been relieved because he venched it out. But it’s all a matter of awareness, if you have a high H2S application, just because you’re treating the H2S with a bubbler vessel or amine plan, or whatever, you have to know that everything on that location is always going to have H2S. Whether it does or not, you have to consider that it does so you’d build procedures in place to protect your personnel.
Terry Nelson:
So we’ve always, when we built a tank battery on an H2S facility, taking into consideration the truck drivers that come in and they may have to vench tanks or whatever. Sometimes they have open thief hatches to pull on tanks and stuff, just to have a procedure and a tag or a sign that says, open so-and-so valve to relieve the pressure and then pop the thief, that way it’s not coming right up in your face.
Jesus Olivares:
I think the other things that have been added in our engineering controls that maybe put it in instead of trying to go in there and gauge your tanks, maybe having some electronics or some level hat tell you more of your levels instead of … I agree with Terry, I mean, when it comes to H2S, the last thing you want to do is the least, I guess human contact you have with it the better you’d be. So anything you can do to avoid that that would be what I would consider first, so being able to look at it from the outside, either electronic or some kind of sight glass. And then of course, we’ve talked about already some of the analyzing inside at least to protect that. So they’re just levels of protection that you want to make sure you have for your employees or anybody gauging.
Terry Nelson:
I mean, think about that nowadays, Murphy gauges and all the advanced level detection, the Sonic stuff, there’s ways that you don’t ever have to even climb a ladder, I guess, to even gauge tanks anymore, but I’m old. So I think about dropping a gauge and …
Chris Smithson:
That’s what’s scary when you go to some locations and they’re doing, to save money, they didn’t even have a flag that’s in the corner to see where the wind is going. Those are the type of locations you really want to make sure you have your monitor and escape pack.
Cameron Croft:
That’s what leads to us driving up but you don’t see any signs or anything?
Chris Smithson:
Yeah.
Terry Nelson:
I remember they issued all the technicians one time, early on when we first came up, before everybody had to scatter packs and everything, they issued these five minutes evac packs. And it was basically a plastic bag that you put over your head and it had a little oxygen tank attached to it. You had to test every so often to feel confident with them, and you had these guys on location with plastic bags over their head running around. It looked pretty ridiculous.
Jesus Olivares:
Yeah, that was pretty bad, by the time you got from the top of the stairs of the tanks down to the bottom, you read already used up all the oxygen.
Chris Smithson:
Yeah, the bag fog’s up too and so it’s just like a fishbowl running around on it.
Cameron Croft:
We were doing a training session and one of our guys, he was an older guy. He is a mentor to me. He was a Cajun but they were talking about the buddy system, and then they said, “If someone passes out on a known location like that, and they fall down, you do not go and get them because there might be a pocket of H2S that they’re running into. You call emergency services, you back away from, so that way you have something.” And then they said, “John, you wouldn’t come after me.” And he goes, “No sorry, I’m not going to come after you.”
Terry Nelson:
It’s funny but on a rig that I worked on off shore, back in the early ’80s, they had three guys that died in a bilge tank because one guy went in and there was low quality air so he suffocated. Another guy went in, three guys went in before somebody said, “Stop going in.”
Cameron Croft:
Well, that’s what they were saying is, your first response is to go in and help them. But they don’t realize that you’re the lifeline, you’ve got to back away so that way you get proper people in that area. But to move on, the last big section is the regenerative process. So amine plants, and I know our company sells amine plants and Terry, you’ve worked on amine plants and Jesse, you built amine plant. So in this case we actually had one question I do want to get involved in this. It says, what gas philosophies are you targeting for the contact tower? I’ve seen point 12 feet per second for unpacked towers, as high as 0.5 feet per second for pack towers.
Chris Smithson:
I think you may actually be talking about both towers and for like scavenger, some people build them out too. They’ll just take a contact tower and they’ll just run it like a circulation pump. And it’ll just keep pumping the scavenger through like a bubble tower or a pack tower, and they’ll use that for contact instead of actually bubbling. The benefit is, you get a smaller tower at higher velocity like you’re saying, but I had to do the math because I’m usually looking at feet per minute. But yeah, 0.12 feet per second is about 7.2 feet per minute. I’ve seen eight feet per minute, that’s probably the standard. It’s in the textbooks as far as the old school methods for liquid bubbling. I forget what they called it, it was Schlumberger process or Baker process, like a powder you had to mix of water and you threw it in the tower and it would bubble. Those are all recommended to the eight feet per minute, which would be about point 0.13.
Chris Smithson:
Yeah, you really want to go above that. You could probably push them maybe to 10 feet per minute, but then you’re looking at potentially carry over and then it gets into, how did you design the vessel? Where’s your liquid level? How much disengagement space do you have? Do you have a mist pack or a pain pack on the top? And what the distance between those things. So if your outlet is a foot away from the top of your liquid, then you probably want to slow it down even more than that. It kind of gets into the design, the other number for the tower, for the unpack power, or I guess for a pack tower, if you’re actually running a structure or a random packing in a tower, 30 feet per minute, or the 0.5 feet per second, you could run like amine numbers or an amine contact tower, it’s like 40 to 45 feet per minute is the recommendation not to exceed.
Chris Smithson:
We usually don’t exceed 40 on ours or else you start getting carry over at the top of the tower. But yeah, you could have, if you’re not atomizing, if you are atomizing a tower you want to slow it down or else all that mist just goes right to the top. But if you’re just dumping it into like a pack tower and you’re letting it dribble down through that packing at 30 feet per minute, you could probably get up to 40 feet per minute and still be fine. But again, it goes into what kind of tower you have. You’re surely just taking an amine tower and then just pumping scavenger into it and you’re just playing with just the tower, then you could go up to that 40 feet per minute knowing it’s designed right. But if you’re trying to remake something and you’ve cobbled something together, it depends on what that design is.
What happened to H2S and CO2 once it is separated from the amine?
Chris Smithson:
So you’ve heated up the amine enough to release the H2S and CO2, they’ll also be a little methane in there because you’ll have some methane that just got stuck with the flow when I went there. So you’re boiling that off and you also have steam in there as well. If you’re targeting H2S, you’re still going to get CO2 removal, unless there’s no CO2 in the gas. When your amine plant absorbs it’ll reacts with the H2S first, but unless you’ve done something pretty creative with your contact power, you’re going to start absorbing CO2. It’s a slower reaction with the amine, but you still are going to absorb it. So if your target is like 4,000 PPM H2S that you need to remove out there and the amine plant is that cheapest way to do it, you’re probably going to get a lot more CO2 than that absorbed out of that as well. Like I said, unless you get creative with your contacting.
Chris Smithson:
So you’re going to boil that out, so you’re going to have this super sour mix of very low pressure gas. Unlike a glycol unit or most smaller glycol units, we don’t operate the reboiler under really any pressure with the glycol, the amine plant will be under pounds of pressure typically. Sometimes with the BibTeX you have like a little bit of ounces of pressure, but the amine plant operates under some pressure to help push things through the still column and the cooler and everything. But you have this really low pressure gas coming out that’s like 60% CO2, maybe 30% H2S and then the rest is like methane. So you have this really low pressure steam that’s maybe not, it’s kind of H2S, it’s flammable. But you got to do something with that so, like Terry said, it’s sent to flare. If it’s H2S though you do have an issue with flaring it, because if you burn it, it turns into SO2. SO2 has its own emissions problem, it’s better than H2S as far …
Chris Smithson:
Well, it’s safer in the immediate term, but SO2 is considered a carcinogenic, it’ll cause cancer. So you can’t do it within like X many feet of people’s houses, so that’s the major downside with H2S removal with amine plant, is how do you deal with that, that by-product from there? So flare combustor, or you can get like super high efficiencies on like a thermal oxidizer where you’re going to destroy the H2S and the methane, but you’re going to have this SO2 problem. We did one application where the flare stack was going to have to be over 200 feet tall just to get the dispersion right from like burning it, that it would disperse enough, because there a house within like 10 miles or something. And so it would be, and that’s what killed it.
Chris Smithson:
The flare was going to cost more than the amine plant was, other issues, some of the bigger plants, like the big amine plants that do have a lot of H2S, they’ll have a clouds unit after them and they’re actually converting the H2S into raw sulfur, and then they’ll give it away because sulfur ain’t worth nothing right now. But they end up with just piles of just raw sulfur. There’s other plants that had some add-on’s to the amine plant, like a little additional things that we’ll do similar thing without the complexity of the clouds process. That use these consumables that can absorb that H2S and create like sulfur cake or something like that. But that’s the big downside to H2S removal with an amine plan. I’ve seen the other question, like if you had a disposal well.
Chris Smithson:
A disposable well would be great, the problem is that it’s coming off that amine plant at a super low pressure, which actually goes into Patrick’s question that he submitted early is that, an amine plant would be the default. He has a bunch of CO2 that he needs to remove from a well, and the amine plants can be the default because it’s going to be the cheapest bulk option to remove CO2. The problem is that CO2 is now 2PSI, and so to recompress that, to put it in a well is going to be super expensive because you’re … I mean, if it’s 30 PSI, that’s not too bad, a compression of a 2PSI, that’s a lot of horsepower for such a tiny amount of volume, and that can get pretty expensive.
Cameron Croft:
Yeah. Well, we can leave that as the last question. So we had, one of our people joining us, he’s from Australia and he actually had some CO2 issues. So Chris, can you quickly give us a brief background on what he’s looking at?
Chris Smithson:
Yeah. So he sent a wonderfully long email. It’s awesome because it’s got all this background information. It’s an interesting story. So they have this well where they have a lot of gas that they used to use for fuel but it’s 40% CO2. So they had a custom power plant that could use that fuel at such a high CO2 rate which is smart because you can send this directly in there, you’re not really treating it. They probably had to do some dehydration or some basic separation, but it’s basically going right into the plant, that’s really cheap fuel. But then they switch it over because the well wasn’t reliable enough to be the fuel source. So they switched over to run on normal gas, which is 95% methane, at least, and so they can’t really use this gas anymore, but they’d love to supplement it.
Chris Smithson:
The problem is, if you try to remove 40% CO2 out of that gas strain, that’s a huge emissions problem. So he’s saying that it’d be basically a million cubic feet a day of CO2 that would be released. So if you were to put an amine plan out there and you can actually bulk remove that much, then you would have quite a lot of the CO2 emissions off that stack. I mean, obviously CO2 is not nearly as bad as H2S, we’re trying to deal with that. But obviously, being in different areas, that’s a huge emissions problem that you might have. So the idea is, can it be injected in a well? The problem is, a million a day at 2PSI, that’s a lot of compression requirements and that’s a very large custom CO2 compressor that you would need to be able to re-inject that down hole.
Chris Smithson:
So he’s asking about, is there any other CO2 options, removal options that might work that could keep it at a higher pressure, so they don’t have that compression requirement? So for CO2 options, amine you’re using your default, membrane will also remove CO2. It has a similar problem where you need that pressure differential to be able to separate out the CO2 through the membrane. So typically membranes, the big problem with membranes is they have a lot of waste gas that goes away with whatever you’re separating. So for CO2, you’re going to lose like 20% of your gas stream that is like meta methane part with it. But for this application that actually might work because you’re just re-injecting it down hole so it’s not really an emissions problem. But the problem is you’re going to have a large pressure drop across that membrane.
Cameron Croft:
Well, we’ve seen that in the past, right? A couple of companies we were dealing with, they were talking about re-injecting the CO2 back down hole almost like creating a CO2 flood. So their by-product waste stream, the CO2 was re-injecting it, right?
Chris Smithson:
Yeah. I think his idea is more a sequence duration of the CO2, not so much like enhancing the oil recovery by using the CO2 to promote oil production. I think it’s really just like, let’s put it underground so we don’t have this emission problem. And putting it back in formation, it’s not going to hurt nothing putting it there. But yeah, a membrane may help with the outlet pressure because then maybe you can tweak the operating in the membrane, maybe out putting like 100 PSI, maybe 200 PSI, which you still need compression for that. But the compressor just probably gets like half the size maybe because the compression, the hard part of it is an exponential curve for compression, it’s easier, the higher, the pressure it is. So a membrane may be an option, the other thing would be a molsieve.
Chris Smithson:
Molsieves are great at removing CO2. They can remove it down to like tiny amounts, but that’s a pretty big molsieve to remove that bulk amount of CO2. And then molsieve typically would do a pressure swing to get that CO2 out of the molsieve so you’d absorb it high pressure, and then you depressurize that vessel and the CO2 will go out of it due to partial pressures between the depressurized gas and the high pressure gas. Typically, to do pressure swing to get that CO2 out of the molsieve, you can’t do a pressure swing with this because then you lose all your pressure and now you have low pressure CO2 again. But you can potentially do a temperature swing absorption with a molsieve, I actually looked it up before this because there was such a curious application for it.
Chris Smithson:
There is ways to do it, there is some people that have done that, they would take some, we don’t do molecular sieves ourselves. We have a partner that would have to do that on the, on that end because there’s a little more involved engineering on that side of things. But temperature swing absorption could be a potential thing. You would need a heater to flow enough high gas over it, to get that CO2 to leave the molecular sieve and then send that at high pressure away back to the well. There probably will be some gas losses with that, with the regen gas and everything, but it could be a way to keep your pressures really high enough to maybe not need compression.
Cameron Croft:
Well, there was … Yeah, to kind of wrap that up, I mean, I was reading on U.K., they actually had the same thing. They had a power plant that was running. So they actually ran a CO2 line back dedicated to, it was like 30, 40 acres of greenhouses and they were actually flooding, like almost CO2 flooding the greenhouses. So it had that rich fertilizer environment and they saw a 30% growth rate. So I thought that was fantastic that that was their way of solving it. It was actually shipping it to a greenhouse.
Chris Smithson:
Yeah, but we don’t know what the greenhouse environment looks like. You have to worry about the heat too, I don’t think it gets too cold there to freeze the plants.
Cameron Croft:
Well, you can do like hydroponics, aquaponics, or something like that.
Chris Smithson:
Yeah. A compressor may be a little cheaper than that. Well, it’s an interesting application but yeah, Patrick, we’d definitely love to talk to you more about it. See if there’s something that we can help you out there.
Amine Plant Tips
Cameron Croft:
All right, well, that’s on the regenerative process. We don’t have too much time left, but on an amine plants, I guess everyone’s always looking for good quick tips to look after. So what are some good tips that you’ve all seen in the past for existing equipment or even new builds?
Terry Nelson:
To me, it’s temperature. We have to maintain a reboiler temperature that is in a range where you’re getting the process that you want, but you’re not using so much water that you have to constantly be adding water to the equation and that affects cost of processing. Whether you have a steam generator or you’re adding distilled water, that’s affecting the cost of processing, and so many times you either have a tower that’s two big, or you have your pressure and the temperature is misadjusted and you’re affecting that throughput through that tower. And you’re either pushing water over the top, or you’re cooking off so much that you’re having to add so much water it’s affecting the cost of processing.
Cameron Croft:
You’re mentioning the still column, so we did have a question come through. It says, can you explain briefly what is the function of the still column in the reflux condenser?
Chris Smithson:
Go for the … Go ahead, Terry.
Cameron Croft:
Go ahead, Chris.
Chris Smithson:
Okay. So yeah, for the amine process and regenerative process, you’re using amine that’s going to grab it and you got to boil that CO2 or H2S out of there. Amine is great for bulk removal of H2S and CO2, just because it is a regenerative process, you don’t have such a high consumable. But like Terry is talking about, the consumable cost can really eat in to your operations if you’re not paying attention to your temperatures and your water use. But you’re boiling the amine, which is, depending on what you’re running, if you’re trying to remove CO2, you are most likely running MDEA, so you’re probably running like a 40, 50% amine to water mix. So mostly what you’re circulating is water. So you got to boil it out, when you heat it up, you’ll release the H2S, CO2.
Chris Smithson:
The still column is going to help with that release, it acts as a heat exchanger for the steam to counteract with the amine that’s coming into the tower to boil it out. For the small plant like this, we do random packing, bigger plants would be like a sieve tray or something on that, but really just to get the CO2, H2S out. And then the reflux condenser is to save that water that you’ve now turned to steam so you can recondense it, and put it back into the system. On a little plant like this, it’s an ambient cooler, on the bigger plant it should to be a forced air cooler. But yeah, if you’re not watching your temperatures, if you’re running a little too hot on your outlet of that cooler, then you’re just sending that steam.
Chris Smithson:
I mean, you’re just humidifying the gas that’s going out, and you’re just sending that out, and that’s all water you have to replace in the system. Because of the heat of reaction with amine when you’re removing CO2 or H2S, the alloy gas is going to be pretty hot out of your tower. So that’s going to suck water out of it as well but also you’re going to boil out a ton of water when you’re heating that low-pressure gas up, and a lot of that water is going to leave with that. So you’re constantly adding water back into the system.
Cameron Croft:
Well Jesse, if you don’t mind explaining, the contact tower, that’s the only thing that really touches the gas that you’re processing. So is that the only vessel that needs to be or is there…Would you recommend other vessels on there?
Jesus Olivares:
Oh, no. I think anything that’s going to have any of the risk side of the gas, maybe at the tower, and you’re going to go into your flash separator and have that, anything going all the way through until you’re able to separate that where once it boils out, even going through the still column I would still think you would want to really consider that, although you’re at maybe low pressure. So the side for me you’re really just trying to protect, make sure you don’t have anything that’s you either going to have stress cracking or you’re going to have, anything you can have in any of your wells or material. It’s very interesting material, and it depends where you are get it from as well. What I mean by that is, is it domestic or from Western Europe. Just because it has a certain spec, what we’ve seen is it doesn’t mean that it’s going to really hold up.
Jesus Olivares:
We’ve had some material that was nicer at buying and still, I mean, when it came back as, our relationship with our customers came back and H2S was eating some of that wall than term materials. So even when you try to protect the whole system, you’re still having issues with that material. So I think it’s almost important, not only that you’re needing things, but you’re also inspecting your equipment. I’m sure you guys have your own equipment and Terry is definitely involved in it, and what we keep learning is, you can’t assume that everything is working so perfect that you have to have that preventive maintenance in there, and you’ve got to be checking whether the walls of it, whether you’re having any contaminants going downstream, whether we have scaling or any of those solar things happening.
Jesus Olivares:
So at the end of the day is, I would consider most of the heating unit as a unit just to, for one, it gives me a least, a little bit of peace of mind that I’m following all the base materials. And then in addition to that, we have our maintenance program and what have you, to make sure we’re protecting ourselves.
Terry Nelson:
What I tell people is, and when I do training classes, I always try to break it down to the simplest terms. I tell people when you look at an amine plant, sometimes you’re intimidated by all the stuff that’s on the skid. But if you think about it, the contact tower removes the H2S from the gas stream. The still column removes the H2S from the amine, so if you think about it like that, you’re sending the gas through the tower, and you’re sending your lane amine through the tower. The amine is falling down through there and stripping the H2S out of the gas stream, so now the gas leaving the contact tower is clean, its sweet.
Terry Nelson:
So now your amine is heavy laden with H2S, so you send it through the still column while you’re sending steam up through there, the steam is going to strip the H2S from the amine, as it falls back into the reboiler, the steam comes out the top of the still column, goes to the reflux coils, where like Chris said, you’re getting as much of that water back as you can. And then the gas off of there goes to flare because it just has the H2S. So it’s a pretty simple process when you break it down to it’s singular components.
Cameron Croft:
Well, speaking on that, we had some questions, so what happens to H2S or CO2 once it’s separated from the amine? And where does it go? I know you said flare, but can you all explain a little bit more on what is that by-product, CO2, H2S, where does it go after that?
Conclusion
Cameron Croft:
Yeah. Well, to wrap this thing up, because it’s getting into everyone’s lunchtime, so everyone’s going to get upset. All right, so if you’re interested in being a webinar speaker or know of someone that wouldn’t be a good fit, please let us know. We’d like to … Our marketer, Tori Valigura, she’ll reach out to you, talk with you, try to get you to come on board. Now, if you are getting a survey, so we’re a Six Sigma company, we love ISO but as the speakers, we like spending the time, but we want to make sure that our information is coming across properly. So please let us know that feedback, you’ll get a free hat or shirt to you, but it will help us tailor it to this thing in the future.
Cameron Croft:
In the future, contact information, you can reach out to me on LinkedIn [email protected]. All of that information will come to our organization so that way if you have a back end where you would like for us to do, more specifically with your clients or just you and your team in general, we’ll set up conference calls. Terry has three to four of these webinars a week that he does, Jesse does his own webinars. So just let us know, we’d like to help you and assist you as much as possible. At this time I’d like to wrap it up. So Terry, Chris and Jesse, thank you all again for coming on board with us, and then, actually, joining us next month for our next webinar.
Terry Nelson:
My pleasure.
Cameron Croft:
All right, guys. Well, let’s go get some lunch. So you all take care. Bye.
