Introduction
Cameron Croft:
All right, welcome everybody. Good morning. Welcome to another episode in Saving Money in Operations. This is requested by our last attendees. This episode is focusing on JT and fuel gas unit operations. A little bit of housekeeping before we get started. This is how you can get a hold of us. I know a lot of people working from home, working remotely, if something shuts down, power, phone call, kid walks in the room, we will record this and upload it to our blog and our YouTube channel, so you can watch it later.
Cameron Croft:
Now, if you’re new to Zoom, what we try to utilize is the question and answer section in Zoom, so if you’ve got questions throughout the presentation, ask those, put those questions in there. I’ll try to interrupt Chris where appropriate, but we do have a Q&A section at the end.
Cameron Croft:
I want to introduce myself. My name is Cameron Croft. I’m the CEO of Croft Production Systems. I got my engineering degree, my masters from the University of Houston along with Chris and then I got my black belt in Six Sigma, so I love data, I love learning. That’s why I actually surround myself with people that are a little bit smarter than me and that’s why I work with Chris a lot.
Cameron Croft:
Chris Smithson, the person that you’ll actually be listening to today is the Director of Engineering for Croft Production Systems. He’s been working with us for about 10 years now. He got his degree, an engineering degree from the University of Houston, so he’s going to be walking us through everything that he does, but he actually does the proposals on the backend, troubleshooting with our service team. He does international consulting work, so he gets hit with a lot of questions today, so again, if you do have questions throughout the presentation, I’ll try to make this interactive, try to give what you need to out of this webinar.
Cameron Croft:
All right, so I asked Chris, I said, “This is what’s requested by some of the attendees. What can we do?” He put this presentation together. I’m not going to read everything here, but he really wanted to touch base on contaminants, composition, some backend vocabulary to set everyone on the same foundation and he really wanted to focus on performance targets for JTs and fuel gas conditioning systems, trying to build out, get a little bit more education on what works, doesn’t work, and then, of course, he wants to end it with case studies at the end.
Cameron Croft:
All right, so Chris, to get this thing started, why did you put this presentation together?
Chris Smithson:
The main thing is to, a bit of education on fuel gas and JTs and cleaning up fuel gas and basically just natural gas to pipeline spec or usable quality for wherever it needs to go. If you can take a look at this graph, it talks about natural gas contaminants, was something we used in our in-house modules to train our new service people and salespeople. You can see NGLs is the last step in removing the contaminants from the natural gas. You want to get rid of particles and liquids first and then take care of the things that are going to be corrosive or deadly. Get rid of the water vapor and the NGLs is the last thing that you attack to try to improve that quality of that natural gas.
Lean, Moderate, and Rich Gas
Chris Smithson:
Yes. We have three examples, a lean example, a moderate, and a rich example of a gas analysis that you might find. These examples, I mean, they can be found anywhere. There’s the lean examples in Permian, there’s rich examples in Marcellus, but these are just representative ones that we’ve done simulations for, for clients over the years.
Chris Smithson:
If you look at the first one, example one. That’s a very lean analysis. Really low BTU, it’s 1022 BTU, 94% methane, very little of the heavier gas components in there, so your pentanes, your hexanes, there’s not much of that in there. That gas, you can put that straight through a generator or gas engine. You know that it’s probably within pipeline spec as long as it’s dry. That gas is really easy to use for other applications.
Chris Smithson:
When you get into example two and example three, then you may need to start looking at potential NGL removal from that gas to get it to a quality that can either be put in a pipeline or used in an engine. You can see the BTU, it’s jumped up quite a bit for example two and you do have a much larger percentage of the heavier components. Example two versus example three, there’s a lot more of those heavies in example three, but even example two may start making liquids at 80 degrees or less. Just because the analysis shows like it’s pretty… looks moderate or lean, it may have a hydrocarbon dew point problem, but you’re really not going to see unless it’s actually run through a simulator or more of advanced gas chromatograph.
Cameron Croft:
That’s right. With these three examples, the next one you’re focusing on is the unit performance for JT skids.
Chris Smithson:
Yeah, so for a JT skid, this is more for a pipeline application. The two main goals are hydrocarbon dew point, meeting that, and NGL recovery. Those are the two main things that you’re trying to do with the JT skid that’s feeding into a pipeline for natural gas processing.
Cameron Croft:
The first one is the hydrocarbon dew point. Explain, especially this chart. I mean, I had to ask you several times what does this mean, so explain what this is going on.
Chris Smithson:
Yeah. This is phase diagram on this chart. This is showing the hydrocarbon dew point phase diagram for the rich permeate example that we had a couple slides ago. For hydrocarbon dew point, the pipeline company, the reason they’re putting that spec is they want to protect that pipeline from liquids forming in the pipeline and creating slugs that may damage downstream equipment or end up in someplace where they’re not supposed to, in the regulator, so it can potentially damage it.
Chris Smithson:
The idea is getting that gas quality to where it won’t create liquids above or below a certain… or above a certain temperature. The idea is this phase diagram, right now we’re looking at it’s about like at the worst-case scenario of like an 800 PSI. We’re going to make liquids if we get anywhere with inside this bubble. At 800 PSI, that’s 105-107 degrees. If we get colder than 107 degrees at 800 PSI, we’re going to make liquids. The pipeline says, “No, no, no, that’s not going to work.” You want to move this whole thing, shift that line to where that bubble doesn’t cross let’s say 40 degrees. Pipeline says your hydrocarbon dew point’s 40 degrees and you want to push that whole phase over, so that they don’t make any liquids if they get down to 40 degrees. That’s mainly the pipelines concern for that, but it’s also a big concern when it comes to fuel gas, too, just for a different reason.
Cameron Croft:
Have you ever heard… I know you do all the requests for quotes. Have you ever heard anyone use cricondentherm?
Chris Smithson:
Once. Yes. Somebody actually did. It was actually in a specification for a pipeline. It’s the first time I’ve ever seen it written in specification. My simulator has the word in there, I had to look it up the first time, but basically that long complicated word, cricondentherm, I’ve only read it, so I don’t know how to pronounce it, it’s basically the worst-case pressure that it’s going to be your pressure at the worst temperature for that gas. For us it’s about a little over 800 is going to have the highest temperature, so if that pipeline’s operating at 810 PSI, then you better be above 107 degrees or else you’re going to make liquid.
JT Plants for NGL Recovery
Cameron Croft:
All right. Well, I know we’re going to use this chart throughout it, so the next one was I guess the focus on the JT is NGL recovery.
Chris Smithson:
Yeah. That’s the other reason to put one on a flowing well where you actually just want to recover that NGL and make as much additional revenue as you can off of it. That means liquefying that NGL, storing them in a bullet tank and that selling them separate from your oil revenue to just make more money off of it, which right now probably not the best option. NGLs is usually you get paid off of… it’s kind of tied to the price of oil, just like minus $20 because it’s harder to transport, harder to store. They knock off some for processing. Back when oil was like $25 a barrel, you couldn’t give NGLs away. The pricing hasn’t really come back on them either, so NGL recovery just strictly for revenue is not really a big thing right now.
Cameron Croft:
So that was the JTs. The next set, our goal is fuel gas targets, which could be a JT, but it’s also other units as well. Explain what this is.
Hydrocardon Dewpoint of Fuel Gas
Chris Smithson:
Yeah. The two main goals for fuel gas, again, it’s hydrocarbon dew point, but from the concern of you don’t want those liquids making it into your equipment. Instead of pipeline trying to protect their thing, you’re trying to protect a burner or an engine from getting slug with those liquids and maybe potentially damage something. The other main goal is BTU reduction. You want to reduce that BTUs so that you get a nice, clean performance from those engines. Those are the two main concerns for fuel gas.
Cameron Croft:
The first one was hydrocarbon dew point, so just like what we frequently discuss, but this is more specific towards engines?
Chris Smithson:
Yeah. You want to get that hydrocarbon dew point low enough to where you’re never going to reach it in your fuel lines. If your hydrocarbon dew point, if ambient conditions, you’ve got your piping exposed on a pipe rack, it’s got to run 300 feet over to your engine from wherever you’re tapping it off of. You don’t want that gas to cool down below that temperature, so you want to lower that temperature enough to where you’re not going to make any liquids in that fuel system and potentially damage something if a liquid slug were to come through because we’ve seen the fuel pots on generators and engines, they’re not very big. A couple of gallons will overflow them and on a natural gas burner, like on a glycol unit, you end up with a bunch of liquid gasoline getting shot through your fuel system, you’re going to have a bad day.
BTU Reduction
Cameron Croft:
That’s liquids falling out, hydrocarbons falling out, so now you’ve got BTU reduction.
Chris Smithson:
Yeah. BTU reduction, some people, they want an improvement in methane number or octane number. Some people, their engine’s specifying a Wobbe index number, which is a BTU. They have to re… a lot of the compressor guys are looking at GERP, which is the gas engine rating program. What it’s doing, it’s taking a gas analysis and it’s saying… running it through what that engine’s going to be doing. It’s going to say yes or no, this gas is good or how much the engine needed to be de-rated.
Chris Smithson:
BTU reduction can be necessary to be able to meet the requirements of programs like that if they’re… what tells the engine whether or not I can use it or trying to just get it… improve it enough to be able to use in those engines. Engines are going to be your application for this stuff. A burner can burn it as long as it’s not going to make fuel or have a hydrocarbon dew point issue.
Cameron Croft:
All right. On the fuel side, you’ve got BTU and then you’ve got NGLs are hydrates falling out. The first step was, which your next slide is basic fuel skid overview. This is kind of either you’re Big Joe, Little Joe, somethings… either your BTU or the liquids are falling out, so this is the first step that… I know we’ve built these, but we’ve seen other of these systems out in the field as well.
Basic Fuel Skids
Chris Smithson:
Yeah, this is usually people’s first stab at fuel gas cleanup, so they’re just like, we know we need something probably. Let’s go with this thing. I’ve seen them at facilities before. It’s just basically the regulator taking two-stage pressure drop through a couple Big Joe’s, separator, make sure we catch some liquids, and then that’s about it. You can make them a lot more complicated. We have, but really these things are only really meant for where you have a lean dry gas. Where the gas is already dehydrated, it’s already… it’s really high methane percentage, so you’re not really worried about liquid. That’s where they’re supposed to be used, but when you use them for richer gas applications, you can run into problems, which we will get into.
Cameron Croft:
Okay. Well, the next one is your PFD of this unit that was previously discussed, so yeah, explain this.
Chris Smithson:
Yeah. These things are super simple. Like I said, they can get a lot more complicated, but basically, you’re just taking two stages of pressure drop, through the first Big Joe and then another Big Joe to regulate it down even more. You have your cold separator there to knock out any liquids, dump valve level control on the separator and then the gas leaves the unit. That’s basically all it’s really doing. Some people build them homemade out in the field, sometimes you buy them with the skid unit, but they are pretty basic. You start adding things like catalytic heaters and heat trays and a dual regulator runs and all sorts of other stuff, you can make them more complicated, but it’s not really going to change what it’s doing or the effectiveness of it by adding more stuff to it.
Cameron Croft:
No. I mean, I guess PRs, pressure reduction valve. Is that right?
Chris Smithson:
Yeah. Yeah, that’d be the Big Joe.
Cameron Croft:
Okay, so why do you need two?
Chris Smithson:
People usually put two just because they like to stage out the regulating. It gives you a little more control if you have fluctuating fuel volumes to have two. If you just had one big one with a big differential, then it’s going to have a small trim in that control valve. Really, it helps to, having the two, they’re not actuating as quickly, especially on smaller volumes they may not be sized properly for, they can react a little better and it gives you a little more wiggle room in there. Plus, you can throw two different heaters on them and try to hope that they don’t freeze over.
Cameron Croft:
Now, that’s… well, see you keep saying Big Joe and Little Joe. Are those trademarked names or what does that actually mean?
Chris Smithson:
They are. I mean, its term is like Kleenex now, but Big Joe is the trademark name for Fisher, they invented the things like 60 years ago, so the Fisher spring on the top, kind of slimline looking regulator thing like that. Everybody builds a knock off of them now, but everybody still calls the Big Joe’s even though they’re the only… Fisher’s the only one that legally gets to say that name.
Cameron Croft:
Oh, okay. All right, so we might get in trouble for saying that name?
Chris Smithson:
As long as we don’t write it down, we’re probably fine.
Cameron Croft:
Oh, okay. All right. The basic fuel skid, so we already talked about the fuel skid and then now you’re putting the example from before, the lean, moderate, rich, and you’re using the lean sample gas composition here. Is that right?
Lean Gas
Chris Smithson:
Yes. This is the lean gas example from the earlier slide. This is the one with the 94% methane, it’s already 1022 BTU. This one, really, you just need to be able to drop that pressure to a usable pressure for your engines or your heaters. As you can see, this one, when we run it through there, we’re getting cold, we’re getting down to 39 degrees on the cold separator, taking these pressure drops, and we’re leaving it 39 degrees through the unit. This one, even though we are getting that cold, as long as the gas is dry and maybe you’re injecting some methanol to make sure you don’t freeze up, you’re not going to make any hydrocarbon liquid. Yeah, you can do your stage drop to this one, you can go through the separators and make sure that there’s no liquids that may have come in through the inlet, any waters or something like that. Yeah, this is a great use for one of these units to where it’s going to be trouble-free for you as long as you make sure you don’t freeze up, so yeah, this is what these units are designed for, this kind of gas quality.
Cameron Croft:
There was a question that just came through right now. It says for the reduction, I guess on these systems, I know we’re talking about it later, but for these systems, for the reduction in pressure, is it not necessary to have a heater, catalytic heater or heat tray, something so that way the valves don’t lock up?
Chris Smithson:
A lot of people do put catalytic heaters on them, it keeps the ice off of the outside. The thing on the volumes that you’re running, this particular example is 400 MCF. Those catalytic heaters hardly add any real BTU into the system, so really they’re just trying to keep the valve warm enough that maybe it doesn’t freeze up and keep the ice off the exterior of it, so it doesn’t cause any physical problems with the valves. Without like a real heater, you’re not really going to impact the temperature of the gas flowing through it, but it does help to protect the valves, especially if you do it in situations that getting to 39 degrees, if you get some frost on it, especially if it’s really cold outside or humid, you may get some ice buildup on it if it gets below 32.
Rich Gas
Cameron Croft:
Now we’re going into the rich, so I guess this is worst-case scenario, there’s a lot of heavies in here. What happens then with this system?
Chris Smithson:
This is a Permian gas example. This is that rich, 1317 BTU coming in, so it’s coming in real rich gas, we don’t have any liquid falling out of it. The hydrocarbon dew point, so like a hundred degrees for this, which is what our inlet is, but basically, if this gas gets any colder than what it was coming in, it’s going to make liquid. As soon as we hit that first pressure drop, that’s where the line goes from the light blue to the dark blue, it’s making liquids. The second drop, it’s going to make even more liquids because it’s got even colder, and then the separator is going to start getting hit with these liquids and separating them out.
Chris Smithson:
Now, the separator’s making about 291 gallons a day on this 400 MCF example, so it’s not a lot of liquid. We did get colder, we’re at 27.9 degrees for this application that has to do with the liquid fallout, why it’s got colder than the other example, but the risk here is that we’re leaving this unit at 27.9 degrees. If we get any colder in that gas, more liquids are going to fall out, so we’re at our hydrocarbon dew point with this particular setup. Like I said, we built these units before, we’ve put them out. They’re not recommended for rich gas applications because you could run into issues, but yeah, that’s the big risk for this. If this is setting out in the Permian, in the middle of winter where it’s five degrees outside because we’ve got a freak cold front that came through, that gas is, it’s exposing those fuel lines running those engines, you can have more liquid fallout and end up slugging separators or building up in a low point and then slugging in and knocking… overwhelming your little fuel pot. Then your engines shut down, then you’ve got to drive out in the snow to go restart a compressor. That’s why adding catalytic heaters, adding heat trays, it’s not really going to do enough to these units to keep them from getting away from that hydrocarbon dew point number.
Cameron Croft:
If you have a basic fuel skid existing, you created this troubleshooting of this is what you might happen. Yeah, explain to us the issue and then how you would go about fixing it or advising on fixing it.
Chris Smithson:
Yeah. The two big issues, you’re going to have freezing and hydrates with the unit. You can have external freezing, which is literally ice buildup on it, those catalytic heaters are really good, especially on Kimray valves, if you’re like a Kimray High Pressure Control Valve to control pressure with a pressure pilot, those heaters are great. Because it’s an open yoke design, the ice can actually, if that valve’s cold enough, build up and build up underneath that stem and then that stem block can hit that ice and not allow that valve to close. Catalytic heaters are important to keep that ice because that ice can physically affect them. On a Big Joe, if that ice gets over the breather plug that’s on the spring housing, and that thing can’t vent, then that… if affects what you’re actual pressure will be because it’s expecting to be ambient and if it’s sealed off, then all of a sudden, that valve’s going to be opening at different pressure. Making sure that physical, like exterior ice isn’t there can make sure you know that things are operating properly, but internal ice, which is your hydrates from freezing up, that gas should be dehydrated before it comes in. If not, you need to be injecting enough methanol to make sure that that doesn’t happen.
Chris Smithson:
Then the outlet being near the hydrocarbon dew point, and that’s what we’re talking about, with that kind of setup, you’re at your hydrocarbon dew point coming off of that unit, so if you get any colder, you’re potentially making condensate.
Cameron Croft:
All right. That’s what you were saying earlier is it might… because there’s no heat exchange, so soon as it comes out of the unit cold bay, you’re dropping it out, you’re having the same issues.
Chris Smithson:
Yeah.
Optimizations
Chris Smithson:
For methanol injection, you can have a hydrate form at less than 80 degrees. We’ve seen them in the field, it’s odd, it’s confusing, it’s not your first thought when you an ice, a line freeze over and you’re dealing with a hydrate and it’s 50 degrees outside and you’re wondering why. If that gas is fully saturated with water, you can have a hydrate at less than 80 degrees. Usually, it’s like 70 is when the bigger risk of it forming is.
Chris Smithson:
If it is dehydrated, you can still have one at less than 40 degrees, so even if you are meeting like a six or seven pound outlet on your dehy, you can have a hydrate if that gas gets down to 35, so you drop it through these regulators. Like, in our example, we were getting down to 37 degrees on the lean one. There’s still a risk that may freeze over even if it is dehydrated. Having at least a little methanol injection can help with that. Some good rules of thumb, we started with a theoretical, but the simulation says hydrates will form, and then used our field knowledge to bump up these numbers. If you have a wet gas, so that’s non-dehydrated gas, you’re going to want five to 10 gallons per million on the low end. If you’re injecting… if it’s like 10 or 20 million cubic feet a day, then you’re not going to need 200 gallons a day of methanol, so that you can start scaling back on the higher volume rates.
Chris Smithson:
On the lower volume rate, it is a little tricky to get enough methanol in there. A lot of times you have two or three-inch pipe, and you’re injecting into that for like 500 MCF. It’s just not going to mix well enough, so sometimes you’ve got to over inject, but if it is dehyd, then you needed three to five gallons per million getting in there. That way you don’t freeze up. Interestingly enough, rich gas will require a higher injection rate than lean gas , so that rich Permian example is going to need more methanol injection. You’re going to be on the higher end of that range, you’re going to be at the five of the three to five versus if it’s a lean Haynesville example, you’re going to be at the three of the three to five gallons a day. That’s just because the stuff that’s in the gas helps the hydrates form.
Cameron Croft:
Okay. That’s on the methanol injection. Then, you have another optimization for a pressure regulator. Is that what-
Chris Smithson:
Yes. This is how do we fix that outlet dew point problem if you already have this kind of unit where you’re just taking these double stage drops, going in the separator and then going somewhere else? When the outlet pressure regulator, that’s adding a third regulator to this setup on the outlet of the gas and increasing the pressure on the separator will help to improve what the performance of this unit is. If we go to the next one, we have another simulation run for it.
Chris Smithson:
This is the same exact example with the Permian rich gas. We have the same inlet pressure, temperature, volume, all we’ve done is we’ve reduced the cut on the second valve going down to 150 PSI to 300 PSI and then now, that outlet valve is going to take it down to 150. Now we’re separating at a higher pressure, which means we’re not taking as big of pressure drop, so going into the cold separator, we’re actually warmer, we’re actually a lot warmer, we’re at 44 instead of 27, but with this, we’ve actually made the BTU on the outlet gas, eight BTU lower, so it’s improved. We’re separating out 77 more gallons a day of liquid, our hydrocarbon dew point’s three degrees lower, which is an improvement, but our outlet gas is three degrees hotter than it was in the first example and it’s all with operating that cold separator 17 degrees higher. We’re operating 17 degrees warmer, but everything’s improved for this unit.
Cameron Croft:
It’s not always about temperature then?
Chris Smithson:
No. That’s usually the default is just make it colder, it will work better.
Cameron Croft:
Right.
Chris Smithson:
If you think of that hydrocarbon dew point, it’s on a curve, so it’s not just a straight line, it’s not like, oh, our pressure’s lower, then we get colder, we get better. Because we’ve increased the pressure on the unit, that stuff’s separating more efficiently from the gas, so because it’s separating more efficiently, we’re getting better performance out of this system at this higher pressure, at this warmer temperature, because we’re separating at 300 PSI, which is a much better… you really don’t want to get much lower than 300 for optimum separation. Even though you are losing the chilling effect, you can see we’re getting improvement out of this system and the big thing is, we’re three degrees lower on the hydrocarbon dew point and we’re three degrees warmer on the outlet. That means we have six degrees that we have to cool down before we make liquids begin.
Chris Smithson:
On the other one, if we cool at all, we’re making liquids, but on this one, we at least have a six-degree window. It’s not much, it’s a lot better than zero. That’s an easy fix, especially if you already have a Big Joe type setup, it’s two more Big Joes to run them in parallel. That way you have backup for them. That’s a pretty cheap option to add to a system like this and improve its performance.
Cameron Croft:
No, that’s good. This is a basic fuel skid example is going through like the first stab at trying to prevent… get the BTUs where they need to be, stop the liquid format. The next one is the JT, which is a massive upgrade. There’s a lot of names to it. They have JT plants, JT systems, dew point control units, you’ve heard a lot of different names to it, but it’s everything utilizing the Joule Thomson effect. Can you explain what that is and, of course, the major components?
Chris Smithson:
Yeah. With this, with the JT unit, we have the same pieces we did in the basic skid, so the PFD is going to look fairly similar with like same pieces. We’re just adding heat exchangers and insulation to… heat exchangers to get a little more use out of that chilling effect and insulation to isolate us from the environmental changes that may affect the performance of the system.
Cameron Croft:
Yeah, so to go on into some of the benefits of going to a JT skid, especially I guess this is specific towards a pipeline.
Chris Smithson:
Yeah. For pipeline spec, you’re trying to meet either a hydrocarbon dew point, you’re trying to remove NGLs, JTs are great because they’re super simple units, minimal moving parts, you just have your control valve and your dump valve really. The standard units, like what we build, industry standard controllers, standard pressure controllers, standard control valves, easy to rebuild, easy to get parts for, and if you have the pressure and you need to take a pressure drop, like a fuel gas application where you have this high discharge from your compression and you drop it to something lower to use for fuel. If you have that pressure available, they’re super cheap to operate compared to like a refrigeration unit where you have to provide the refrigeration to be able to get the chilling effect for it, but if you have the well head pressure, they’re super cheap to operate if you need to take that pressure drop for it.
Cameron Croft:
I know this is an upgrade from the basic fuel skid, so a JT, you can utilize it for a full-on, I guess, full well, full midstream processing, 10-20 million. Then, this is also an upgrade where you can apply these systems, just a fuel gas.
Chris Smithson:
Yeah. The big benefits are it is simple. I mean, you’re not adding any more moving parts than you already have with the basic system. The big benefit, though, is that it’s warming that gas after the pressure drop considerably because it’s going back to the heat exchanger and it’s getting you better performance out of that system. You’re getting a lower BTU on the outlet and you’re getting a much larger hydrocarbon dew point difference because you’re achieving a colder temperature and the gas is coming out warmer, then you’re able to get a lot better performance out of that system.
Cameron Croft:
A PFD, explain to us what’s… walk us through this.
Chris Smithson:
It’s the same pieces that we had before, we’ve just added some heat exchangers to it. Where gas is coming in, we’re going to go through a liquid gas exchanger to pre-chill that gas. We’re going to go through the gas to gas exchanger, which is going to do most of the work. Some units only have those. They don’t have the other one. Then we’re going to take a pressure cut all through one control valve and going into the separator. The control valve on that, I see the question for it, we use standard control valves on the smaller units, just your standard stem guided ones on the small ones. On our medium and larger JT units, we’ll use the piston balance ones, which is what you typically use for any sort of good pressure control and sized properly. These are standard controls for it.
Chris Smithson:
We’ve done some really big units where we had to go to a special trim because of for volume reasons. It takes such a big pressure drop, it gets loud, so we’ve had to use the super fancy Fisher noise reduction trims before, but for the most part, we’re just using standard control valves, your Mallard or Norriseal type one. Fisher is an upgrade if you want to pony up the cash for it, but yeah, it’s just a standard stem guided control valves. Then, we’re leaving back through the gas to gas exchanger, through another pressure regulator to give that final fuel gas outlet pressure and then off the skid.
Cameron Croft:
You still have a pressure reduction valve on the backend holding, I guess, a little bit more back pressure on the cold separator. Is that right?
Chris Smithson:
Yeah. Yeah. That allows us to give the fuel whatever the fuel needs to be. If the fuel needs to be at 100 PSI, needs to be at 50 PSI, that valve can give it that, while we can get whatever we need on our cold separator to optimize the performance of the unit.
Cameron Croft:
Okay. All right, so now we’re going apply this PFD. You headed first to the Permian, which is the high rich composition from earlier.
Chris Smithson:
Yeah. If we were to use it on that lean gas example, we wouldn’t get any liquids out of it. That lean gas example has a hydrocarbon dew point of negative 60 or something. You’d have to get so cold that it’s not really feasible to do anything to that gas because you don’t need to it change anyway because it works fine. The benefit of using this for the lean gas is that it would warm the gas back up, it’s more of a controlled pressure regulation and then, you say, well, you’re… not that that’s really a risk, but if you don’t want the gas that cold, which can be a problem, then the JT could fix that, but for the rich gas example, we’re moving a lot of liquids off of this gas stream.
Chris Smithson:
Our gas is coming in, we’re cooling it down. I’ve bumped the volume up because usually on the JT skid, you’re going to be moving a little more volume. Like, our small standard unit is two million a day, so I ran this one at 1.5 million coming into the system. Taking the same pressure drop, a hundred degrees inlet, but we’re removing 4,200 gallons a day of liquid from this system. We’re getting down to negative 15 and that’s at 300 PSI, and then the outlet regulators are going to take us down to the 150 PSI. We get a much, much better improvement in this gas quality. We’ve taken the BTU from 1317 to 1169, so we were at 1250 I think on the basic fuel skid, whereas this one, we’re 1169. It’s double the improvement in BTU and this gas should give no problem running in most engines. It definitely in the burners is not going to have any problems with this kind of gas. Mainly because we’re really eliminating the heavier hydrocarbons, your C4, C5, and C6.
Chris Smithson:
C6 is what really gives engines problems. Your C5s can be problematic, too, but if you can get it down to point zero something, then you’re making a much bigger improvement in the gas quality. Caterpillar updated their program a couple years ago to take a bigger effect of C6 in it because they’re putting these units in a lot richer gas applications when the shale boom was really hitting really big and they made the C6 a bigger impact on the de-rate for these engines because it really is a big detriment to being able to run these engines effectively and reliably to get that C6 out of there.
Cameron Croft:
Well, then we actually had one question while we’re on here. It says, “I’ve seen a few designs with the liquid don’t have downstream gas liquid heat exchanger. I wonder if that’s a problem with gas coming back to the cold separator. I meant the gas from cold liquid due to the gas liquid heat exchanger.”
Chris Smithson:
Yeah. With the way we have it drawn, we have the dump valve before the heat exchanger. He’s talking about where they… and I’ve seen this on units where they have it after the heat exchanger. I’m not a fan of putting it after the heat exchanger. I don’t know if it’s quite a risk, like what he’s talking about with… because technically, as it warms up, you’re going to have a multi-phase flow. As you can actually see with the color changes, the pink in this simulation is liquid and then the dark blue is liquid and gas. As soon as we went to the dump valve, because we dropped pressure, we had a bunch of gas flash out of it. Now, if we put that dump valve after it, you would see the same thing happen after the exchanger because it’s warming it back up, you’re going to flash a bunch of gas out of it.
Chris Smithson:
I haven’t really seen a concern where the gas would actually bubble back into the separator. It would stabilize the liquid for you, knock a little methane out of it, but because it’s flowing, I wouldn’t really consider that a concern that it may come back from the liquid gas exchange. Due to the high differences, usually it should just keep continuing down the line like it’s supposed to. I like to have a dump valve before the gas exchanger because it does give more cooling effect to that exchanger. It operates at a lower temperature, so to have that dump valve before it instead of after it, but I’ve seen it done both ways. It is a little safer to have the dump valve after the exchanger because it’s a little warmer going to the dump valve, less likely for the dump valve freeze over.
Cameron Croft:
Well, then I know you’re… You’ve got an example two, Permian, so this is the… what is this? Is this the exact same? Yep. Exact same composition.
Chris Smithson:
Yes.
Cameron Croft:
What are you trying to say here? What’s this?
Chris Smithson:
The big difference here is instead of… this is for the operator that says, “You know what? Negative 15 is good, but my engine’s running a little rough for whatever reason. Maybe if I make that fuel skid work better, it will work better.” They go and they drop the pressure on the main JT valve to get the unit even colder to improve the performance of the unit. In this, we took the exact same example, we just dropped our choke from 300 PSI to 200 PSI and the outlet valve is still taking it down to 150.
Chris Smithson:
Now our cold separator instead of operating at 300, is operating at 200 and we did get colder. We went from negative 15 to negative 26, so we are getting colder, but if we look at what the performance is, our BTU’s worse. Our BTU is 1174 instead of 1169. Our liquid, instead of 4,200 gallons a day, we have almost 3,900, so we have 300 gallons less that we’re making and the reason for this performance is that phase diagram that we talked about because with the pressure, it’s low enough you can see that the way that that curves toward the bottom, you have to get even colder to make up the same performance at those lower pressures. That extra bit of cooling that we got by dropping that pressure a little bit more, did not improve performance for us. This unit’s actually working less, working worse than it was operating at this lower temperature, lower pressure, than it was before.
Chris Smithson:
Running the simulations, knowing the optimum pressure to set it at is important, but a good rule of thumb is set it at 300 and if it’s good enough, just leave it set there. Usually, you’re not going to see any performance improvement below like 275, 260. Dropping any lower than that, you’re really not going to see much.
Cameron Croft:
You’re saying the cold separator, leave the pressure on that at 300-275.
Chris Smithson:
Yeah, yeah. Leave the cold separator pressure at 300 and if you’re operating a unit that doesn’t allow you to do that, put that outlet valve on there, so that you can have that back pressure. Most of them operate pressure reducing, so it’s different. If you can’t hold that much, hopefully your separator’s rated for it, some of those fuel gas skids are only rated for like 200 PSI, so don’t overpressure them. Yeah, a JT unit should have a high pressure rated separator that you can operate at at least 300, 350 something, and if you are getting too cold or you’re operating fine, but you actually are getting too cold because you have let’s say too much pressure drop, you can back off on that JT valve, up that cold separator pressure without… If you don’t have that outlet valve, then you’re stuck at whatever the main JT valve can output. Yeah, this is an example of just because it got colder, doesn’t mean it got better.
Cameron Croft:
Well, we have to tell that to our service guys. Sometimes they get in that mentality that, well, just get it colder, more will drop out, so they immediately start turning that T12 controller, trying to reduce that pressure and get colder temperatures. In this case, it’s not solving anything.
Chris Smithson:
Yeah, because it’s the easiest thing to change. You just crank that pressure controller and, all of a sudden, the whole unit gets colder, but yeah, you can see it actually made for worse performance in this instance, which is the same thing that we saw with the simple, basic fuel skid. We held a higher pressure on the separator and got better performance out of that unit at a warmer temperature than we did getting down to that lower temperature. It’s the same effect. It’s optimizing that pressure is super important.
Cameron Croft:
Okay. Well, some of the… now there is some issues with JT, so explain to us about the troubleshooting that you… because you handle all of our service guys troubleshooting calls, so you have to I guess give advice constantly on this. What are the troubleshooting issues?
Chris Smithson:
Yeah. From an operational standpoint, the only reason that unit’s going to stop working is if the pressure controller went out or the control valve went out. Like, physically just not holding pressure like it’s supposed to or the more common issue is you had a freeze up and you just can’t blow gas through that, so you had some sort of hydrate form that’s blocking off that glass flow. That goes back to the methanol injection on these units. If you’re running a JT, you want methanol injection. If you don’t need it, you want to have it available just in case you do freeze up, but it’s the same issues, like on the other skid, your internal hydrate risk and then you have your external ice risk. Because everything’s insulated, your valve should be the proper ones for a JT unit where the ice shouldn’t affect them, but it is something to look out for.
Chris Smithson:
The other issues is the unit not meeting hydrocarbon dew point or a lack of NGL production if that’s what you’re going for, so maybe you’re not getting cold enough, you’re not at the optimum separation pressure, or you have really high temperatures coming into your JT plant. These are all things that can affect our performance of the system.
Cameron Croft:
Well, so the optimization on that, they’re calling in, saying we’re having these issues. These are, I guess, what you would advise on fixing first?
Chris Smithson:
Yeah. If it’s a freeze up issue, a lot of times with JT units, you want multiple injection points. It’s like the unit that we showed you have the liquid gas exchanger, you have the gas to gas exchanger. You may freeze just in the small cooling effect you get from that liquid gas exchanger, so you probably want methanol coming in at the beginning of the unit, but you also want it in right at that JT valve because if for some reason it may not have mixed properly or well enough, the JT valve, right after that valve, is the coldest point of the unit. You want that methanol to be right there, available for it. Multiple injection points in the JT unit. Some of our bigger ones, we have up to four on the system. We’ll run multiple pumps for redundancy, but making sure that methanol is getting into those multiple injection points, don’t just put one point that’s injecting into two different pressure areas because it’s all going to go to the lower pressure, so making sure that methanol is properly getting into the system is pretty important.
Chris Smithson:
Then, for getting the unit to perform better, reducing the inlet temperature of the unit is a big thing. Some of our smaller units, we put out coolers, like little ambient coolers just to knock off that inlet heat because any temperature drop you can get to the inlet of the unit, you’re going to see that same thing on the cold separator. If you take it from 120 to a hundred degrees coming into the unit, you’re going to see that same 20 degrees translate into your cold separator, so that knocking 20 degrees off the front is going to get your 20 degrees colder on the cold separator. Whatever you can do, if that means running an extra cooling loop, running an extra pipe just to dissipate some of that really hot heat off of like a compressor discharge or something or if you have a cooler onsite, we’re taking the gas after the coolers for fuel gas instead of before the cooler.
Chris Smithson:
Then increasing the pressure of the JT unit will give you a little extra boost. Then, optimizing the cold separator temperature and pressures to where they’re in the right range. If you’re a little out of whack on your pressure, getting that where it’s supposed to be. Maybe changing out a pressure pilot. If you’ve got a Kimray pilot and your trim’s too big on your valve and that thing’s searching a lot, you’re seeing big swings in your pressure, operating pressure, maybe it’s time to change that trim out on a valve more accurately for what your flow is or maybe get a better pressure pilot, upgrading to a more expensive one that will get you a tighter window on that operating pressure.
Cameron Croft:
Well, I had one question pop up. It says, “Now you’re saying that methanol injection points and you were talking about two spaces earlier, where do you recommend to inject methanol?”
Chris Smithson:
The main ones is at the beginning of the unit because as soon as you start cooling, you’re going to need it, and right before that JT valve. Those are the two main points of it. We’ve added other points where we’re injecting the cold separator and for halfway between the exchangers, but right… if you only have two, right before the unit and right before the JT valve are the two critical points to have it.
How reliable are process simulations?
Cameron Croft:
All right, so the other question is, “How reliable is the process simulations?”
Chris Smithson:
Well, I’m sure if there’s any engineers on the phone, you’ve heard garbage in, garbage out for any of these programs. It really is, is it setup properly? If you’re trying to say like, I’m getting to this temperature, is this output simulation accurate? The simulators are super accurate for that. I didn’t believe it at first, when I first started we started messing with the simulator and everything, we pulled a gas analysis and double checked it because I was like, it’s math, how can it be that accurate to what’s seen in the field? There’s got to be some variables, but the actual output of what it is, is like the unit’s getting to 30 degrees, I’ll pull my gas analysis sample, take it to the lab, get it sampled. The output from the simulator and the lab match very accurately. Within a couple percent of each other. That output is good.
Chris Smithson:
The tricky thing with the simulators is the knowing how to put the exchangers in for these type simulations where it’s just basically exchangers, knowing how to put those in properly, so that it’s running them properly through the simulator. That’s the tricky part because you can get some crazy results from them if you just do a real simple heat exchanger setup, it will lie to you all day long telling you it’s a negative 300 or something and you’re making LNGs somehow with like a 500 PSI drop. Yeah, it can get bad.
Cameron Croft:
There is even a few, like you said, junk it, junk out, because you were playing with, 10 years ago, you were playing with them and you can make it do whatever. Even when we’re shipping you requests for quotes right now, and then the client comes back and says, “Look, this is what the other company can achieve with their unit,” we’re looking at, we’re like, this is impossible. This is not physics.
Chris Smithson:
Yeah.
Cameron Croft:
I mean, but like you said, you can manipulate the heat exchangers. There’s some variables and there’s the more accurate you are setting a foundation, knowing what your system can do, then you said a couple percent off on compositions, as we’ve seen in the past when we actually pull
Chris Smithson:
Yeah. Yeah, so we did it where we had that simulation, like the Permian one, if we were to put that unit physically in the field, on that gas and then pull a gas sample, it would match within a couple of percent if we’re achieving that temperature. Now, are we going to achieve that temperature. Is it all the parameters are exactly the same, is the outlet temperature exactly the same, the pressures available exactly the same, but if you make a match, the outputs match. It can be tricky and in simulators, I mean, they get more complicated the more components you add refrigeration unit, there are dozen different ways to do it.
Where do you inject methanoyl?
Compressor De-Rate
Cameron Croft:
Well, on your next one, you had a compressor de-rate. Explain what de-rate means and go through this. This is our first case study.
Chris Smithson:
Yeah. The issue that the client was having is they couldn’t de-rate the engines enough to use that existing fuel gas. They have the gas analysis, so okay, we need compression and they’re just like, “I can’t run on it, the engine won’t let me run and I can’t de-rate this engine, which is de-rating the timing of it,” so that the pistons in a different position when the ignition happens, so you don’t damage the engine. Because of the volatility of the fuel gas, they couldn’t de-rate an engine enough to be able to use it on that fuel gas. This was an instance where they had a little setup already for separators and Big Joe’s and it just wasn’t… and they pulled a fuel gas sample, it still wasn’t good enough for what they needed to be able to run. The unit they were running was an old compressor that sounded terrible. You could hear it vibrating in their truck. You could hear the ground vibrating just because the thing was so loud. They were trying to upgrade, get some more volume and everything out there. They needed fuel gas for this, but the newer engines need a little cleaner fuel gas and you just wanted better, more reliable.
Chris Smithson:
Our fuel gas skid, which was our half million a day fuel gas skid, which doesn’t have quite the exchangers as our dedicated JTs do. We call it our FCS 500. It’s got a pretty good JT on it, just not nearly as good as our standalone, but it was taking the BTU from 1251 down to 1190 and with the cold separation temperature of 28 degrees, which doesn’t sound super cold. We’re not at zero, but with that level of gas chilling, with it we were able to not have to de-rate the engines at all. The engines could run on it. They got everything they needed out of that gas. Even just getting down to 28 degrees, because we were moving so much of the heavier components that were in that gas because it was very, very rich gas.
Cameron Croft:
The problem with this case study is that compressor de-rating is of course they’re having unexpected shutdowns or they’re having to de-rate the engines so they can’t move as much. Is that right?
Chris Smithson:
Yeah. Yeah, so the compressor company, they have the unit. They’re like, “Man, I really want to get this in the field. It’s not making me money sitting in my yard as a lawn ornament,” so they want to get it out there, but they can’t use that unit on that gas. They could build a brand-new one with maybe a fancier engine controller on it that can do it, run on that rich gas, but they want to use what they have. They want to get out that equipment that’s already existing. To do that, they need to make that gas work for that engine instead of trying to get the engine that works for the gas.
Compressor Horsepower
That’s right. On your second case study, this is a compressor horsepower.
Chris Smithson:
Yeah, so the issue that this rental company was having was that they couldn’t get full volume through their compressor. They couldn’t get their nameplate volume, so they have X amount of horsepower out there, should move X amount of gas. They couldn’t get that full volume because they were de-rating their engines because of the quality of the fuel gas. Similar problem to the first one, but the client, they needed to move more volume. They’re like, “Man, we’ve got this much horsepower, move that much volume,” the compressor company’s like, “We’ll just send another compressor and we’ll get you all the volume you want.” The client doesn’t want to drop an extra $40,000 a month on more compression, so instead, cleaning up the fuel gas was a great option to get what they needed to out of those compressors. By cleaning that up, getting a better quality gas to those engines, allowed them to get that full nameplate capacity out of that engine, so no de-rate, full horsepower, they were able to bump up the volumes that all the units were moving, so they were able to get the client what they wanted as far as full volume through that system.
Compressor Uptime
Cameron Croft:
That’s good. Case study number three was compressor uptime. I guess the downtime costs money, but I think a lot of the contracts we’ve seen is what, a 95% to 99% uptime, runtime if they want.
Chris Smithson:
Yeah. Some 98, yeah. [inaudible 00:49:19] 95, if they’re lucky to get that.
Cameron Croft:
Yeah, explain this case study.
Chris Smithson:
Yeah. This particular one, this one I felt bad for the operator because they bought the compressors back when I guess these companies were flush with money and could do things like drop millions of dollars on compression. It was the operators that had to manage these systems. The issue that they were showing up, when the gauger came around every day in the morning, at least one of these three units would be down. This was across multiple, multi-compressor sites, so at least one of these things was down every other day. The peak of those issues was in the spring and the fall and the reason was, is because if the gas is warm and stays warm, you’re not going to have liquid fallout. If it’s cold and stays cold, you’re not going to have liquid fallout, but in the spring and the fall where it’s cold in the nighttime and it gets hot in the daytime, liquid starts to fall out in different places where it shouldn’t fall out. It may make it through the separator and then run through a bunch of exposed piping and then the liquid starts to fall out of it. Then it gets sucked into a fuel gas line, goes straight to a fuel pot, overwhelms it, the whole unit shuts down.
Chris Smithson:
That was the issue that they were seeing that these engines were shutting down on misfires or bad… basically bad fuel gas quality. The engines don’t know that. They just say like, help me, I’m exploding, turn off. They were seeing production losses of 10,000 to 15,000 a month per compression facility because there’s gas lift. If they can’t send that gas lift gas back to those wells, those wells don’t produce, so they were seeing quite a lot of losses and the fuel gasket, this one was easy. You get this little 500 MCFA fuel gasket, this is actually a rental we rented to them for two grand a month, which 5X on their… they pay us two grand a month, you’re going to make 10 grand.
Chris Smithson:
That was a great deal for them, and it freed up the operator because the operator’s not wondering as he drives up, is this compressor going to be down, am I going to have a headache this morning or not? The problem was the hydrocarbon dew point, and they had some basic fuel gas skids on this. It was kind of cool to see. The first time I’d seen one completely covered in ice is a 16 inch separator that was just a giant ice cube because of the temperature difference going through those regulators into that separator, but yeah, just wasn’t, because of that, any liquid fallout after that skid just went straight into the fuel pot and overwhelmed the fuel gas in those units.
Cameron Croft:
Well, then our last case study, the first three were compressors, the last one’s I guess a more pipeline focus.
Chris Smithson:
Yeah. This one’s about the pipeline hydrocarbon dew point. The client was getting shut in. I think on this site, this site we had our dehy on and that’s why our field guy was there. He was taking care of that. It wasn’t our JT unit, but the fuel guy was complaining because he’s getting shut in by the pipeline thing. You’re not meeting hydrocarbon dew point. Hydrocarbon dew point’s 40 degrees, you’re not meeting it, you’re shut in. He’s upset because he’s running his JT unit. He was running it at like 35 or 32 degrees or something and he’s thinking he’s fine and he’s optimized that he’s not running at zero because heat exchangers don’t need to run at zero. He needs to run at 32. The hydrocarbon dew point’s 40. He’s thinking he’s fine, he’s optimized, he’s a smart operator. He’s trying to reduce compression and everything, so he’s operating just where he thinks he needs to be, but he’s not meeting spec.
Chris Smithson:
Well, he sent us a gas analysis, the field guy was talking to him. He explained the problem to me. We ran it through the simulator, realized that he’s not meeting spec because they’re recompressing that gas at 700 PSI, when they recompress it, it’s out of hydrocarbon dew point. At the 300 PSI that he was running through that JT, he was at 32-degree hydrocarbon dew point, but when he increased it through the compression, he was at 45 degrees. It’s like, okay, easy. Just drop six degrees and go below it.
Chris Smithson:
He increased his pressure coming into his JT, he got a little colder on it, and he was able to meet the spec, but it is confusing because you think like, oh, I’m meeting the spec, I’m at right temperature, but really you’re not. That’s what that has to do with that curve, that hydrocarbon dew point curve, that cricondentherm word. It’s the worst-case scenario. It’s with the… it’s the pressure that you’re going to be at the worst-case temperature and that’s the temperature that has to be brought down. For him, he bumped up to 700 PSI, he was outside of it, he was past the line and got shut in. Yeah, it was an easy fix, so he was back online within a couple days.
Compressors
Conclusion/ Q&A
Cameron Croft:
If you’re interested in being a webinar speaker or know of someone who would like to be a good fit, please let us know. Reach out to Tori.Valigura@croftsystems. We’d like to talk with them and try to get them onboard, so that we can help share this knowledge with everybody. You are going to be getting a free survey outside of this. Please fill it out. Tell us… I’m Six Sigma, so I love feedback controls, let us know how we can improve. What are other things? Would you like resources outside of it? That’s actually how we’ve tailored a lot of these presentations, figuring out what everyone wants. Now, there is going to be a section on there, reach out to [email protected] or you can put in this system if you want PDH credit, if you’re a PE trying to get continuing education credits, let us know what it is, so that we can get this shipped out to you.
Cameron Croft:
Part of questions and answers at the end, so I’ve got two loaded questions right now from someone in the webinar when they were first signing up that they had, but again, if you have questions outside of that, please fill it out now. The first question is the JT skids for treating fuel gas for compressors, how to keep conditions coming out of that JT consistent?
Chris Smithson:
That’s a tricky question. My assumption is his problem is he’s seeing variable outlet gas quality basically out of that unit. I guess I’ll tell a story for that one to explain the issue that we saw. We had a similar problem at one of our sites where we were seeing fluctuating out of the BTU’s from the JT skid, which I’m guessing that’s probably his problem, too
Cameron Croft:
He works for a major compression company, so I imagine he’s focusing on that.
Chris Smithson:
Yeah, so at certain times of the day he’s probably seeing the engine runs rough or something like that, it’s not quite meeting what it’s supposed to. That’s tricky. We had a site where we were fuel gas for compression, the gas was coming in. The JT unit basically what it’s going to do is like even if it maintains the temperature all the time, the quality of the gas coming out is not going to be the same if the inlet varies. If the percentages are changing on your inlet of the JT unit, the percentages are going to change on the outlet, too. The liquid recovery may change as well even though you’re staying at the same temperature. If your hexane number is trying to creep up, then you’re going to be separating out more hexane out of the unit, but a little more hexane is going to be sneaking by.
Chris Smithson:
If the analysis that we have with their… we take the hexane from 1% down to like .02%, but there is still some left in the gas. If it was 2% hexane coming in, we may be taking it down to .04%, which doesn’t sound like a lot, but it does change the BTU because hexane is such a much higher BTU and it does affect the quality of the gas. What you’re getting into the unit if that’s fluctuating, then it will affect the performance of the fuel gas unit for what you’re getting out of it. The unit’s still operating. You think it’s operating fine because none of the operating parameters have changed, pressure, volume, temperature, none of that’s changed, but if your composition’s changing, then it will affect what your outlet is.
Chris Smithson:
Basically, you want to get the worst-case scenario gas analysis. If you send it to somebody like us, we’re going to run a simulation for you. We want that worst-case analysis for it, so for the application that we have where we have the same problem, the gas coming into the compressor site was originally was like a hundred degrees coming into compression, into suction of compression. Compressor was heating it up if they had it after coolers and everything, so it was going through there. They’re getting down to like 120 and then it came around to us about 110 before it actually hit out fuel skid. We were having no problems. Well, this client brought on a bunch of wells. They had a fracking program going, they’re drilling had finished up and they came, and they frack four or five wells within less than a month. All of these wells that were brought on were a lot hotter and a lot more liquid’s coming up with them, they were super rich, but they were so much hotter.
Chris Smithson:
The suction of those compression was now like 140-150 coming into the unit and the compression, you squeeze out some compression, you have the scrubbers on there, they’re making liquid, their liquid production shot up and I remember talking to my compressor tech. He’s like, “You need to fix your fuel gasket because I can’t move enough volume through my compression. I need better fuel gas.” I’m looking at him saying, “You’re at 150 degrees. You’re liquefying a third of this gas stream. You’re never going to move the volume you’re supposed to because you’re liquefying it. That’s just physics, pressures and temperatures.” Really, once they realized that, and it’s like, “Well, we need to cool this inlet. We need to do something here or else we’re never going to be able to move the volume that we’re expecting to through the outlet of the system.”
Chris Smithson:
Because of those high inlet temperatures, the high temperature’s going carry a lot more of the liquids, it jumped up our hexane number like two or three points and that really affected the inlet composition to the unit. It would fluctuate throughout the day because of the heat, like 5:00 in the afternoon you’re seeing 160 degree gas coming to that station, but at 7:00 in the morning, we showed up first thing and it’s a little cool outside and it’s coming in 120. I mean, it made a huge difference in the quality of what was coming to us. That’s something you just can’t change. You’d have to know what that change in quality is and you’d have to get much colder to effectively have the same gas quality coming out the back.
Cameron Croft:
If you’re having high fluctuations, I’m trying to remember on that one we finally got where the gas analysis was taken beforehand. Right? We were able to say this unit was designed for this, this composition, this… and now, after three, four months, this is what they’re at right now. Then, they were able to get that analysis and talk to their client and we can start dictating, getting better temperatures.
Chris Smithson:
Yeah. Usually we’ll get… like a lot of clients will be like, “Heres’ six analysis. I don’t know which ones the right one. They’re all… this is every one I have.” “Okay, we’ll just pick the worst one.” There’s six wells coming into the station that’s maybe a fuel gas. We didn’t ever pull this fuel gas sample. We’ll just take the worst one and just shoot for that because if it can work on the worst one, then they’ll be fine. The problem was this primer’s changed. We’re six months in and all of a sudden, they’re bringing on these new wells, much hotter temperatures, and then we really, it’s difficult.
Chris Smithson:
The other difficult thing was those engines, they had to be manually adjusted to the quality of the gas. Like a big, like 50 BTU swing took operator involvement, so that just made it trickier to have to deal with.
Cameron Croft:
The second question that he had was JT with dump valves are backing up, resulting in higher BTUs and periods of rich gas coming through. How would you prevent this?
Chris Smithson:
We’ve actually seen this problem before, too. Horizontal separators, especially small ones can be tricky to set a level controller on. My guess is that his level controller, the liquid level’s getting too high and the separator is carrying over through it and that gas a lot of times will get re-vaporized because it was separated at cold temperature and then once it gets warmed back up, it will actually flash back. Most of it will, so you will get left with some that won’t, which can be problematic. Yeah, setting those level controllers, my recommendation, just try to set them as low as possible. Try to adjust… you can adjust the window. If it’s a switch, change the switch out for the box, if it’s the box, change it to where it’s just really small dumps and just try to put them at the low end of that window as much as you can.
Chris Smithson:
Like, if you barely get any liquid in the sight glass, you always want to be able to see in the sight glass, but if you get any liquid, let it dump away to just where it barely see it. It can be difficult. Maybe go to a more expensive brand level controller that may not be as finicky on the controls, but that is a problem that we’ve seen before. It’s the skinny horizontal separators that are tricky on it [inaudible 01:02:45] fuel gas skids we do verticals just because they give a little more slug potential to them and they’re a lot easier to set a level controller on.
Cameron Croft:
Well, that’s good. Well, I don’t see any other questions pop up and we’re kind of ending up our time. Again, there is a survey outside of this. Fill out what you thought about the webinar, what would you like to see. One of the questions is, we’re having a round table discussion, bringing a bunch of subject matter experts on and just opening the floor to everybody and just bombard them with all the questions that you have. I’m kind of looking forward to that. Our next webinar is in two weeks, 9/15, it’s over Amine, Glycol and Coalescing Filtration, so we’ll go from that. Chris, thank you for joining us and I know it’s lunchtime, so everyone that was attending this webinar, I thank you for being a part of this today
