Introduction
Cameron Croft:
Welcome everybody to our webinar that we’re having on-field gas. We’re specifically looking at dual-fuel, natural gas-powered, and E-fleets today. This is coming from a lot of our clients reaching out to us, wanting to know more about our products and how the industry is kind of converting their systems into this trend. So what I want to do is introduce the speakers. I’m Cameron Croft and I’m CEO of Croft Production Systems.
Cameron Croft:
And today who’s actually going to be doing most of the speaking is going to be Chris Smithson, our director of engineering over at Croft Production Systems. He gets the credit and the blame for most of these projects. So he’s going to be the one most privy to talk to us today. Now, we designed today’s outline to talk specifically and try to hit as many of the questions that we received in the past.
Cameron Croft:
These highlights, we’re going to be talking about the challenges of the field gas, the gas composition, contaminants, gas BTU, where to source the best field gas, average fuel volumes. Then Chris is going to go really deep into the specific requirements that he needs to get a better concept of what our clients are looking for and then the deep dive into the equipment itself, and then the recommended options that he has.
Cameron Croft:
So to kind of get started on what we’re talking about today, we’re going to start with the challenges of field gas, gas composition basics, and varieties of field gas. But before we get started on that, I do want to talk about basic terminology. So Chris, can you explain to us a little bit about what you’re saying, the difference between dual-fuel and by fuel, natural gas-powered and E-fleets?
Dual-Fuel VS. BI- FUel
Chris Smithson:
Yeah. So these is a few vocabulary definitions. This is how I think the generally accepted definition for what these are. I mean, certain people use these interchangeably. But basically, you have a dual-fuel versus bi-fuel. So dual-fuel means that you can run two of the fuels at once versus bi-fuel, which is you can run one or the other in the same engine without modification.
Chris Smithson:
So a dual-fuel set up would be like a diesel engine that has a natural gas air mixer in it that can also substitute natural gas instead of diesel, saving you some of that diesel costs, versus bi-fuel can maybe run on diesel or natural gas, but it’s one of the other, and it has to switch and runs a hundred percent on one or a hundred percent on the other. So dual-fuel is pretty common for what we see.
Chris Smithson:
A lot of people have diesel engines already. So they’re switching those or modifying those to be able to substitute that diesel for cheaper natural gas. And then the other big thing is natural gas-powered versus an E-fleet. So we hear a lot about E-fleets as being the future of fracking. But a lot of spreads are starting to move to natural gas-powered spreads, where that is the natural gas engine directly powers the pump versus an E-fleet, which is making power, and that power powers an electric motor, which powers the pump.
Chris Smithson:
So they have different requirements. Natural gas power typically has multiple smaller engines versus one big generator that is creating electricity for the entire site. So just basic definitions to these things. They have different requirements to different ones as we get into it, different pros and cons to different ones, but that’s basically how we see these definitions.
Cameron Croft:
No, that’s good. I’m glad we’re doing that because you’ve corrected me a number of times in the past where I just off the top of my head keeps saying E flight. You’re like, “That’s not it. That’s not it.” So everyone keeps making the same mistakes with that. Now, kicking off, the first part is the challenge of using field gas. I know this is a huge question because everyone’s trying to get into it and they were like, “Let’s just tap straight into it.” So talk to us about the spectrum of a wide variety of field gas.
Sources and Composition of Field Gas
Chris Smithson:
So field gas is not like the typically sourced fuels that you can get or maybe you’re used to getting. So normally things like diesel, gasoline, CNG, LNG, are all consistent things that every time they show up, you’re getting the exact same fuel. It’s what we’re used to. It’s what we’re used to putting in our cars. You expect to get the same thing. No matter what station you go to, you’re always going to get the same fuel.
Chris Smithson:
So field gas is not like that. Field gas comes in a bunch of different flavors, varieties, compositions. So there is a lot that you have to look into to make sure that this is going to be compatible with what you want. Because from field to field, from location to location, you may be a mile down the road and you get something completely different. So just a little example of what those different variations could be.
Chris Smithson:
Right here we have three examples of different gas analyses. These is the compositions that make up that field gas coming out of the field. So you’re going to have… And these are percentages so they should tally up to a hundred. So like 94% methane for this first one in example one. Two, almost 3% ethane, and then smaller percentages of all the heavier stuff. And then usually it gets smaller and smaller as you go down.
Chris Smithson:
And that totals up to 100% of the gas and a BTU of about 1022. So that’s a pretty lean gas sample. BTU is not very high. It’s mostly methane. But you can get a richer analysis that’s going to have more of the heavier components, which is going to drive up your BTU. In this example, we have Haynesville, Gulf Coast, and also Permian.
Chris Smithson:
That’s not necessarily what you may find within Haynesville. You may have a Haynesville example that looks like example three, or you may have a Marcellus example that looks like Haynesville. So it can vary wildly depending on where you’re located and where you’re moving within the fields. But basically, you got to look at these compositions. Sometimes they’re only just a little different. Sometimes they can be a lot of different.
Chris Smithson:
But the main thing is the heavier components that are on this list are what really give the field gas problems. So the heavier ones are more likely to create knock or misfires within like reciprocating engines. They’re more likely to fall out as liquids within the gas stream, especially after pressure regulators. So those are the kinds of things that we usually target for NGO removal or extra separation or filtration and things like that.
Chris Smithson:
But here are some examples, and you can see how much the BTU changes. There’s almost a 250 BTU difference between examples one and three. So it’s a big difference that you can run into from these different samples. And the other thing that’s not on this chart is the inerts. So like H2S, CO2, nitrogen, the actual inerts. Those things, when they show up on analysis, you do need to take those into account.
Chris Smithson:
A lot of CO2 will lower your BTU and can trick you into thinking that, oh, you have a low BTU sample. This is better gas. But it may be so high in CO2, it’s hiding some of the heavier stuff. H2S normally doesn’t even show up on a compositional analysis like this. So if your client comes and gives you that gas analysis report, it may not have H2S on there. You may need to look at a separate note for H2S on that analysis because they have to test that separately. It doesn’t show up in normal composition.
Chris Smithson:
So taking a look at that analysis and being able to see what’s on there gets you an idea of what that gas quality might be when you’re looking at it is important. But yeah, it comes in a lot of different flavors, and being able to see each one and look at each one separately is important to make sure you’re not going to get surprised.
Field Gas Contaminants
Cameron Croft:
Yeah. So there is a huge variety of field gas, even in these locations, just driving two miles down the road you’ll see a different variety, a different composition of the gas. So you’re talking about contaminants, and I think that’s actually the next section. We’re going to be talking about specific contaminants that we look for in each. So break this down for us and like the over high-level view of the contaminants that you look for.
Chris Smithson:
Yeah. So the picture on the right side of that flame, if you think of the percentages we saw on the last one like the biggest percentage is methane. It’s the largest part of a flame. Then you have ethane, propane, butane. As the molecules get heavier, there’s less and less of them. And then you have what we consider condensates, which are your hexane pluses and maybe some of the pentanes in there.
Chris Smithson:
And then you have your stuff that doesn’t burn, your nitrogen, your CO2. H2S kind of burns, but you don’t really want that in there. And so those are really considered non-energy components. Those are really more of the contaminants we want to remove. Hydrocarbons are the stuff you want to burn. But looking at the particulates or the contaminants, these contaminants, this is kind of the order that we like to remove them in this chart on the left.
Chris Smithson:
So basically the first thing we want to get rid of is particulates. They are the most physically damaging thing to the equipment. So something like frac sand that’s coming up with blowback, that can erode dump valves, it can erode pipe, it can mess up heat exchangers, it can file the internals of equipment. So that’s something that we want to remove first. That way, that doesn’t create problems in the other equipment downstream.
Chris Smithson:
Now, hopefully, they have something to remove that, but big upset or a slug or something like that, you can end up with sand in places it’s not supposed to be. The next thing we like to remove is bulk liquids. And then maybe after the bulk liquid, some finer separation. But that’s your oils and your water, your condensates. Getting that out of there so that we can process just gas because it doesn’t always show up as just gas sometimes.
Chris Smithson:
Then sometimes we want to remove heat. Heat can play a factor in what your actual BTU is or what you’re trying to achieve. In later processing, heat can mess up those processes. So sometimes we want to cool that gas down. It makes the process better and can give you a cleaner gas. And then H2S and CO2, they’re both corrosive. They both have negative effects on the gas quality. But the big thing is that H2S is deadly.
Chris Smithson:
So even if you can accept a small amount of H2S, then you may still not want to just because of the safety involved if you do have H2S even a little bit running through the equipment on location. If you’re running pneumatic systems and you have spy gas that you pull directly from that, and you get H2S coming out of a level controller, it may start setting up little safety alarms. And then your little pager thing starts going off and the safety guy freaks out and starts shutting things down.
Cameron Croft:
Do you even think that’s a possibility with like an E-fleet and stuff where you’ve got 30, 40 guys running around a consistent well site if there’s any H2S present?
Chris Smithson:
I mean, it’s never enough to really be a problem. I mean, the engines aren’t designed to be able to burn. The highest number I’ve seen is like 300 PPM into an engine. And so that’s not going to be enough to actually make somebody pass out or something if you did have a leak from it. It would take a very specific kind of leak and just the right environmental conditions and terrain and everything to make that actually deadly.
Chris Smithson:
I mean, if you’re not around H2S and the safety guy just… The limit is 10 PPM and as alarms go off, they want to shut things down and check everything. I mean, it’s usually just better just to get rid of it and remove that separately. And H2S can come in all sorts of amounts. I mean, you could be at 30 PPM at one well, go to the next well and it’s 3000 PPM.
Chris Smithson:
And that can be the difference between the uneconomical and economical treatment of that gas. And then H2S can get expensive to treat too. So getting rid of that and knowing how much you’re actually going to receive is important. And then after those two, really we like to get out water vapor. So that’s not water-like liquid water in the gas, that’s like humidity in the gas.
Chris Smithson:
So the way we have humidity in the air, the gas has the same thing. What can happen is as the gas gets cold, it’ll start freezing up. You can have what we call hydrate plugs, which are internal ice cubes forming in the pipe at below 70 degrees. We’ve had them where they formed at like 65 degrees in a pipe. It feels wonderful outside. Why is my pipe frozen? It’s just because the pressure and the temperatures are just right, that you got to hydrate plug, and now you have no field gas.
Chris Smithson:
So water vapor can be really important. Even when you don’t need to remove anything else because I guess it’s super clean, like up in the Marcellus where that gas comes out of the ground, like 98% methane, you can still have it when you need to take a pressure drop to send it to your fuel system and you freeze up. So sometimes that’s the only real processing that we’re doing is removing water vapor for some of these field gas samples. But it can be important. It reduces corrosion and some wear and tears on your engine as well.
Chris Smithson:
Reciprocating engines, that extra water can cause problems like oil and stuff, and then create a need for more changes. But once that’s gone, then we can go after the NGLs. So the NGLs are what we call condensates in this other diagram. So this is your natural gas liquid. That stuff that if we chill the gas, we can remove because it turns to liquid and we can separate that out.
Chris Smithson:
And then once it’s separated, you have a cleaner, lower BTU gas that’s just those top components, the methane, ethane, propane type stuff. But this is the normal order that we’d like to remove things then. Get rid of the bad stuff first and then work our way to the cleaner stuff, to removing the NGLs.
Cameron Croft:
Well, and that said, so kind of falling into the gas BTU. That was our next big focus or topic we were wanting to touch base on. So these are two examples that you have coming into it. So explain, kind of go a little bit more into the BTU of the gas because that seems to be a huge question that we’re getting from people operating these sites.
Chris Smithson:
Yeah. So BTU is often a specification that the engine manufacturer is going to give you for your field gas. They want a certain limit of how hot that gas is coming in. If it’s too hot, it can cause problems with it. Some manufacturers will give you a lower BTU. They say no more than 1150. And they’re saying that because they know if the gas is not hotter than 1150, it shouldn’t have the heavier stuff in it that can cause problems.
Chris Smithson:
Now, most of these engines will run on 1300 BTU, 1400 BTU if it was just methane and ethane because there are no liquids to fall out and it’s consistent fuel. But the manufacturers may be conservative and saying like, “Oh no, the BTU has to be this low,” just to protect the engine because they’re afraid of what you might put into it for these different field guests samples.
Chris Smithson:
BTU can be tricky. These little tables are screenshots from our simulation program. The LHV and the GVH are the lower heating value and the gross heating value. Sometimes gross heating value is also higher heating value, sometimes the HHV. But the BTU, it’s good to know when they’re asking you what the requirement is if it’s the higher or the lower BTU number because there’s both.
Chris Smithson:
It’s different from the heat of the water vaporization when you actually burn it. But other specs they’re usually talking about the higher heating value, that gross heating value is what they need to be under to have a gas that’s usable for those engines. I prefer using the Wobbe index for a number, for the gas quality. Wobbe index is a much better example of the interchange of the ability of the gases.
Chris Smithson:
So if you know what your Wobbe index was at site one and you know what it is at site two before you move and it’s pretty similar, you know you’re going to end up running about the same that you were. It’s more about the actual burner inside the system. That Wobbe index is taking account like specific gravity. So it’s more of how interchangeable this is.
Chris Smithson:
It doesn’t really matter if like, oh, you got a bunch more ethane, but you don’t have the heavies. And so the BTU kind of looks the same. The Wobbe index kind of equates these better. So you know, like, Wobbe index is really good to have like, okay, these are… They’re all within like 10 or 20 of each other. So these are all going to give me the same quality of gas that I had at this other site.
Chris Smithson:
BTU can sometimes be affected higher with like the inerts, like CO2. You have a real high CO2 and you think your BTU is good because it’s like 1100, but then you realize you have 8% CO2 and it’s just dragging down your BTU number. And so when you actually try to run the gas, it actually runs really rough because you have all this heavy stuff in there that wasn’t taken out.
Chris Smithson:
So BTU is important. Wobbe index is a really good equalizer across these different ones. Everything’s just a different combination in all these different hydrocarbons. With field gas, it’s just not a consistent thing. So it is helpful to have something that can be consistent. But a really good way of if you don’t have the BTU, but you have the analysis to figure out if it’s going to be richer lean is just looked at the methane percentage.
Chris Smithson:
So we have it listed here as C1. And so that C1 number is methane. If it’s like 69% or 67% like these are, that’s going to be a really rich sample. That’s a real high risk of rough stuff in the gas that’s going to make your burn rough. If you’re running a reciprocating engine, you’d have to de-rate these engines because that gas would probably give you misfires, which means you lose horsepower.
Chris Smithson:
So it can cause problems. Seeing these things, if you saw like 90% methane, then you know that’s a better sample. And so being able to see these and have a decent idea of what you’re seeing on these gas now it’s going to really help you filter through some of these pretty quickly and see like, oh man, this one’s going to be troublesome or, oh, this one should be pretty good. Or at least taking minimal conditioning versus a lot more work to get it out.
Chris Smithson:
But the heavy hydrocarbons, the stuff at the bottom, like the C6’s, the C5’s, those are the stuff that gives your engines problems, especially reciprocating engines. If you were to put this analysis in Caterpillar’s program for how that gas is going to burn, they take a big effect on the C5’s and C6 for whether or not that’s going to be a good gas to run their engines.
Chris Smithson:
They weigh those higher because they know the effect that that will have, potentially damaging their fuel systems. So you definitely want to see small, tiny numbers on those heavier hydrocarbons at the bottom of that analysis. Because if it’s bigger, if it’s like 1% C6, which is hexane, it’s going to be rough. You may have liquid fallout and it’ll probably give you some field problems.
Best Sources of Field Gas
Cameron Croft:
Additional questions on that. So we’re going to go into another one, which we’re getting from the questions is best source of field gas. So we kind of threw this quick thing together, but kind of go through the spectrum of what you’ve seen and what we’ve been on in the past.
Chris Smithson:
So the best place to get field gas is obviously cleanest source that you can find. So where is the cleanest source going to be in the oil field? It’s going to be after a processing plant. Ideally, it’s going to be what the neighbor’s house is getting. If you run a gas line from his house over, then you know you’re going to get the best field gas. It’s going to cost you more to do that and the neighbor is going to be pissed, but that would be the ideal gas that you could get from an area.
Chris Smithson:
The closer you get to the wellhead, the worse that gas quality is going to be. The more processing it’s going to take, the more risk that you have, that you may have an upset with your fuel system. So kind of the basics of you have your wellhead, so you could tap in right after the wellhead, but you don’t know what’s going to come up with that gas, water slugs, oil condensate slugs. A rich well is just going to have liquids coming up with it. So you don’t want to be right there.
Chris Smithson:
We’ve been on sites where we’re pulling right after initial separation. The initial separators are good. They get most of the liquid, but they’re only designed to get most of the liquid. Upset scenarios. We’ve had slugs run pretty far through our equipment and it can be pretty problematic. And at least after initial separation is where you want to be. You don’t ever want to try to pull right after the wellhead.
Chris Smithson:
You want to be after the whatever the first separator is on location minimally before you start trying to do anything. Compressor stations and gathering stations, these usually have some sort of processing on them and they usually have higher pressure gas. And we’ll talk on the next slide about why a higher pressure can be better for you. But if you can pull gas from after the gathering station, like at the outlet of the gathering station, that’s usually going to be cleaner gas than what is going to it from the wellhead.
Chris Smithson:
So sometimes that may mean you got to run a little pipe to do that. You may have to run a polyline from that compressor station back to your well pad to be able to get that field gas to you, but that may be cheaper than what the conditioning equipment required to get that gas the same quality that you could have gotten at the back end of that gathering station.
Chris Smithson:
So you don’t want to have to add a bunch of extra equipment if you don’t need to, because that’s just going to drive up your conditioning costs for it. But if you can get from the backside of a gathering station the high pressure, that’s probably going to be the cleanest gas that you can get in the field reasonably. And some fields may have processing plants where they’re actually like removing CO2 and they’re really driving that water content down and getting it like really clean, that would obviously be ideal, but those can be pretty far away to try to get gas back to you.
Cameron Croft:
And that’s one of the questions that came up was, what kind of longer pipeline are you pulling to locations instead of using the wellhead gas? Is it a welded pipe or high pressure hose? What are you seeing?
Chris Smithson:
So the longest we’ve been from a gathering site back to the well site was a little over a mile. And they ran a poly pipe, like the big roll poly pipe, high pressure back to the well site because we needed pressure. On the well site, it was only like a hundred pounds of pressure, which isn’t enough to really clean up anything. You can’t really condition very well. All the separators are bigger.
Chris Smithson:
And so we can get 1,000 PSI if we got it off the gathering station. So they brought it back in high pressure poly pipe, which for like a dual-fuel setup, you’re not talking about a lot of field gas. So like a two inch polyline should be able to bring you all the fuel you need, which isn’t too expensive. On the site that we were at, we were moving 8 million. So that was a three inch line that we were pulling through there.
Chris Smithson:
I mean that, that site had some other issues. But it was just a lot. We were able to pull the fuel we wanted to from that. It wasn’t too bad of a cost for them to just run that temporary polyline back. It was a fracture job. So it was only there for a week and a half or so. But sometimes if they have separate lines running for each well back to the gathering station, one site that we did years ago, they would send us the field gas back down what would eventually be the main line for the gas to go to the gathering station.
Chris Smithson:
So we’d send the field gas back on that line. We’d pull that. We’d do everything, the drilling and the fracking from that. And then once the well, it was time to produce, it would produce back up that line. But that only works if you have like multiple lines for every single well, which most of the time they combine them all together instead of just one line. But this particular site, they had several ones.
Field Gas Pressure
Cameron Croft:
Let’s go into the pressure a little bit because that’s what we keep talking about is the high hydraulic pressure, getting it back and you keep starting the processing. The higher the pressure, the better. So let’s go into the specifics of that.
Chris Smithson:
Yeah. We’re coming at this from gas conditioning people. Our job is to clean up the gas for either as fuel or used for our clients to sell it to a pipeline. So that’s where our focus comes from. So for us, we always want high pressure. So it’s a lot cheaper to run a low pressure polyline to bring that low pressure gas over to you and hook into that. But if we can have 1000 PSI, 1100 PSI, then that high pressure gives us a lot more room to do different things with the conditioning, to get the gas cleaner, to give a better product to those engines.
Chris Smithson:
So here we have two samples. It’s the exact same gas composition that came out of the well, we just have it at two different pressures. So 300 PSI on the right and 1100 PSI on the left. There’s a BTU difference between these two gases just because of the pressure change. So this gas was run through a compressor and the BTU is actually lower by 35 BTU just because the pressure increased.
Chris Smithson:
So then this goes to why… And like the methane percentage increased, some of the heavy numbers decreased just because the pressure was increased on that gas. So that’s why I say, if there’s a compressor and you can pull that high pressure gas off that compressor and route that to you through like a high pressure polyline, yeah, it’s going to cost more for that high pressure, but that’ll give you a better quality gas just from that compressor. So then when you’re conditioning, it’s going to do even better to give you even better quality gas.
Chris Smithson:
So when you’re dealing with field gas, really sourcing is an exercise you kind of have to do every single time. And obviously, hopefully the clients would help you with this. It’s their gas that you’re pulling from them. But the main questions are, where’s like 1,000 PSI ish source of gas that’s near here? What kind of processing is being done to that gas beforehand? How far away is it that we’re having to bring this gas back to?
Chris Smithson:
Because if you’ll have to pull off the well pad every single time, it can be rough. We’ve done some smaller locations where we’re bringing in compression to boost that up so that we can get that gas clean enough for those engines. That doesn’t really economically work on the bigger frack spreads. When you’re moving 8 million, the compression cost and the mobilization for those giant compressors is just astronomical. It just kills economics.
Chris Smithson:
So if you can find the higher pressure and bring that, then it’s better off. Or we do all the processing on the well pad. We had one site where we did that, where we did all our processing on the well pad. And we got like three in a row where we were able to just send the field gas conditioned to the location, and we did everything on the gathering site. So all the liquid that we separated, all the vein gas and everything, all that went back into the gathering facility.
Chris Smithson:
So none of that had to be done on the site, that way we weren’t in the way of everything as well. But being able to source it, checking out, working with the client to find what the best sources can definitely save you some money and headache in the long run.
Volume for field gas
Cameron Croft:
Well, average field gas volumes. So you’ve talked about temperatures and you’ve talked about pressures now it’s kind of going into the volume, how much you’re actually needing for field gas. So you got some specifics here. We’ve got three different scenarios that we’re going to, but let’s talk about this first scenario. And then if you can kind of go into each of those applications.
Chris Smithson:
Yeah. So this first one is a smaller one. The upper picture is for field gas for natural gas compressors. These are big caterpillar engines that are only running on natural gas. And then the lower one is for a drilling rig power for a dual-fuel, where we were supplementing natural gas to diesel engines to drive down their diesel costs. And with natural gas, compressors are always running and they need a hundred percent of the time.
Chris Smithson:
The dual-fuel, obviously we’re trying to get like a high substitution number, the higher, the better because the gas is a lot cheaper than diesel. But for what we typically see for compressor stations or drilling rigs, it’s about 500 in the CF a day is an instantaneous max that you got to pull through there. When the engines running max, you’re going to have a certain fuel rate.
Chris Smithson:
A lot of you field guys probably look at it in like cubic feet per minute or cubic feet per hour. So whatever that max rate is, it’s important because that tells us like the max size equipment needs to be. But then you have your average daily usage, like what your actual daily consumption is going to be. And then that informs things like consumables that may be needed for the unit or long-term runtimes on certain things.
Chris Smithson:
So knowing that is also important well, and that goes into your substitution. So even though it’s a max of 500 MCF, they really only pull 250 to 350 MCF a day of actual usage for it. But we have to be able to size for that high-end number just to make sure nothing carries over that’s not supposed to.
Cameron Croft:
The next scenario is kind of getting a little bit higher fuel, which is the natural gas-driven frac fleet. So this is kind of where you have to start beefing up your operations a little bit. You have kind of go into these case studies too.
Chris Smithson:
Yeah. So dual-fuel is convenient because you can always switch back to diesel. So there are definite benefits to being able to do that. Some of the bigger natural gas-driven fleets can also switch to diesel. But on the dual-fuel setup, if the gas just dies off, it automatically switches to diesel. Typically, you’re already set up to continue running on that for days if you need to.
Chris Smithson:
So it’s not quite as critical to have some of the safety systems or the uptime systems for some of these field gas systems. If you are running strictly natural gas, then you may want some extra redundancy in that unit to be able to make sure that you can stay up as much as you’re hoping for. But typically what we see for these kinds of setups, a typical dual-fuel application from what we’ve seen when we’ve put this equipment out is they’re running a max of 3 million instantaneous flow rate.
Chris Smithson:
But it averages out to about one to one and a half million cubic feet a day of actual consumption for the fuel. And then there’s also, usually if we’re talking about fracking, then there are periods of shutdown in-between the stages. So unlike the drilling rig, the drilling is kind of always-on all the time. It just kind of ramps up and down. For fracking, you actually do have shut down periods. So it is important to have equipment that can start up and shut down immediately. Now, when we’re trying to remove the liquids, which we’ll see later when we get into the equipment, that can be a little tricky.
Chris Smithson:
If you’re trying to cold separate just to start and stop, you lose a little efficiency with that. But having equipment that can just start and stop is pretty important. These were both trailer-mounted units that we had. And they were drilling rig units that were oversized to be able to also power the frack spreads that were brought in. And these both went up north. And so they had dual-fuel frack systems that would pull the field gas from it. These were strictly just separation and dehydration. The gas was clean enough they didn’t need to change the BTU of it. So we scaled the system down to just be what was required for that so that they could have clean gas for those engine systems.
Equipment Required for Processing Field Gas
Cameron Croft:
This is the one to three million into these. And then we kind of get into the bigger applications, which is still natural gas driven, but then you get into the like E-fleets. So this is up to 11 million, or what we’ve seen so far of up to 11 million that we’ve worked on. So yeah, I explained. Now, for all these operations just kind of scales up, we have a little bit more redundancy built in. So explain this a little bit.
Chris Smithson:
Yeah. So this is for dedicated natural gas powered applications. So either you have a generator that’s only running natural gas or your engines are actually powered by natural gas. So for these systems, we’ve seen six to eight. We’ve planned for up to 11 million. That’s kind of pushing like the max for a mobile system. But the actual usage is really more like three to four million, the total consumption per day.
Chris Smithson:
And that depends on the types of engines. Certain engines have different efficiencies, the runtimes are different The E-fleet, they’re usually powering other things. So there may be a secondary generator that’s always on that’s powering other things that runs on natural gas. And then the main turbine is what gives the site power. That may turn on, turn off. Other ones where they’re powering individual turbines, they may not have the same efficiency as the big turbine. So they have a little higher gas usage.
Chris Smithson:
It really depends on what your particular setup is and how you’re getting that gas in the system. These big systems though, because they are a lot larger, we have a little more leeway to put extra safety systems on them, an extra redundancy on them. And then depending on what you’re trying to achieve, trying to lower that BTU, extra filtration, maybe slug protection. Because the client keeps saying that there’s no liquids in the gas, but then all of a sudden, a couple of thousand barrels show up.
Chris Smithson:
Being able to protect against these different things is pretty important. These are all skid mounted equipment, but we can also do trailer mounted for these as well. It definitely helps, especially on the frack setups. Being able to move a trailer is a lot easier than the skidded equipment. But we do like to have a certain amount of equipment for in case something fails, we have at least somewhat of a backup of it for it to keep things running at least to the end of the stage. That way, we’re not having an immediate shutdown in the middle of things.
Cameron Croft:
Well, in the scope of work, it really is hard to figure out. You’re trying to accommodate all the variables, pressures, temperatures, H2S, the Wobbe index, figuring out the BTU levels. But then also the big scope of work for each of these is mobility. How quickly can you just move it to the next site, plug in? Some of our clients want the full, like you hit a button and everything’s triggering, everything is going into a readout.
Cameron Croft:
So it’s hard to… Like you said earlier, we’re scaling up, trying to build it in these redundancies, but also under that contingent of you got to still stay mobile because it’s all about speed. Because these frack guys, man, they’re phenomenal to watch because they’re running 24 hours. I mean, they do not stop. They just keep moving. So anything shuts down, it puts them behind. We’ve talked to a few of them where if they’re behind two hours, they start planning that that’s going to affect them months from now. That they always have to stay on schedule. So it’s always that timeline for them.
Chris Smithson:
Yeah. And we prefer to come from it like… So our primary business is running conditioning equipment to the actual producer of the oil and gas to get their gas into the pipeline. So we’re used to being long-term on sites. We’ve seen a lot of problems and that sort of thing. So there’s always the trade-off, will this work? Well, yeah, technically that’ll work. The question is, how long will it work?
Chris Smithson:
It’s like, yes, you can run a generator on that gas, but are you going to blow it up in six months when you get a slug through it? Because you got a little Parker coalescing filter that’s just a little inline, a screw pipe thing that can barely hold a gallon of liquid and that was the extent of the gas conditioning that was put into the system. But yeah, it’ll work great for six months until any amount of liquid came through and then blew up your filter.
Chris Smithson:
Or this system, which can handle X amount of liquid coming into it, all these failure conditions that the clients said probably will never happen and now our gas is good. That’s the way we like to come at it to make sure that there’s a solution. That you won’t want to get hammered with a giant slug or, oh, the gas is dehydrated, but is it really? You need to be able to handle that.
Cameron Croft:
It’s that risk management and trying to figure out the probabilities of failure throughout the whole system. We actually had another question just come through, how do you dispose of the produced NGLs? I know we got fallout multiple areas, and then we even have a JT system on some of these locations. So how are the clients, their multiple ways of disposing NGLs?
Chris Smithson:
Yes. So the standard way if you want to try to sell it would be to put it in a pressurized tank. Well, you have three different liquids that may come off of it. You have water, you have oil, and then you have your NGLs, which are your cold separated liquids that are going to turn back into a gas if you don’t keep them under pressure. Typically, if we can, we send all that back to a gathering facility or a compressor station. They can handle that.
Chris Smithson:
Option one would be dump everything into one pipe and then all the liquids back together, and then that’ll be separated and managed properly at the other end. The opposite end of that option would be to have a separate water tank, oil tank, low pressure separation to separate those two, and then a separate NGL tank to keep that under pressure and then truck that away.
Chris Smithson:
Now, that’s a lot more tanks and expenses to do all that. Again, if you have benefits of being on the gathering sites when we’re doing this field gas application and just send the fuel to the location it can be beneficial because then all the liquid can stay on the gathering site that’s usually meant to handle at least a certain amount of that. But that can be tricky. And again, it goes into, where did you end up? How far are we from other infrastructure?
Chris Smithson:
What are we going to have to do at this particular location? It becomes site-specific to what you can do. And are you making any NGLs? Certain sites just don’t really, are not enough to warrant any sort of like pressurized tankage or anything like that. A little off gas you may get as acceptable losses and you can just send that to the water tank. Other sites like the one where we had the high pressure polyline coming to us, we had a equally sized line going back because of all the liquid that was falling out on that site.
Chris Smithson:
There was liquid showing up with the gas, even though it came in as a gas to us in the start that polyline. By the time it got to us, it had cooled down, liquid fallout. Huge separator with a bunch of liquid fallout. We had an inlet separator, that had liquid coming out of it. We had our DI vessel and we had another separator, that had liquid coming out of it. Plus the client’s fuel system which had some separation and a bunch of liquid coming out of that too. I mean, we were sending a tremendous amount of liquid, but we were sending it all the way back to the gathering facility.
Chris Smithson:
So there was actually two polylines run, one for the gas and then another one. It was slightly smaller, but running back for the liquid at a lower pressure to send all that back. But again, it’s site-specific to what’s going to make more sense. Does it make more sense to split tanks? Does it make more sense to run a pipeline? How close or far away are we from these other things?
Field Gas Application Requirements
Cameron Croft:
We can kind of go into a specific. And that’s kind of leading into the next one is, what are the specific requirements of that first thing that client comes and talks to you? You pretty well have your checklist of what you dig just to even start kind of getting a concept of what they’re needing. So do go into the application requirements. I know we’ve already touched the volume, pressure and gas, but these other things. And if you don’t mind, a couple of snapshots of why this is important.
Chris Smithson:
Yeah. So just the quick highlights. Max instantaneous rate tells us how big certain equipment needs to be to handle your max volume that you need. Daily volume rate kind of informs us about consumables and some of the other equipment so that we know what amount of volume is actually running through the unit. If you give it to us in cubic feet per hour, that may be great for your instantaneous runtime, the max that engine’s going to pull.
Chris Smithson:
But how many cubic feet for the day are you actually going to pull through there? Are you up 40% of the time, 60% of the time? Those kinds of information can help us figure out what that daily gasoline is. Field gas pressure that you need going into your fuel system. Obviously we’re going to have whatever the pressure of what we can source it at. But then also, what pressure do you need it at?
Chris Smithson:
So if we can get it at 1,000 PSI and all the pressure regulation down to output it at 100 PSI or 300 PSI or whatever your particular fuel system is requiring. And then BTU, the field gas, or Wobbe index, those kinds of requirements usually come from the engine manufacturer for what they’re allowing as far as gas quality. Sometimes they have compositions that they allow. Sometimes they want to see like max H2S or CO2 allowable.
Chris Smithson:
They don’t want to see over a certain amount of nitrogen or something. Sometimes they have a lot of requirements. Sometimes they have like four. But whatever the engine requirements are, typically, it’s something like a BTU or a Wobbe index number. And then they’ll have like specs that say I want more than this or that, or H2S or CO2. Usually it’s like 25 PPM H2S is pretty standard for like reciprocating engine type field trans.
Chris Smithson:
Turbines can actually handle more H2S. A lot of them can. But again, it’s more of a big safety thing. Just because you can put 300 PPM through a turbine, do you want to? Do you want that emission problem? Can you have H2S running through all your conditioning equipment? For us, the answer is no, we don’t want H2S running through our JT’s or our DI’s. We want that separated ahead of time.
Chris Smithson:
But yeah, just trying to figure out, what are the actual field gas requirements that you need? And then it gets into the sourcing natural site requirements. Where can we get the gas? How far is it coming from? What pressures and stuff that you’re going to get it at?
Cameron Croft:
Well, those are the applications coming into it. We do want to discuss quickly, I know we’re starting to not really run out of time, but I want to go into the specifics of the equipment required. Now, we have several other locations, blogs, actually other videos that we’ve done talking specific about each equipment that’s going into it. But let’s give a overall view concept of what you start with. And then we’ll go into the specifics of each piece of equipment.
Chris Smithson:
So this kind of goes to the way we like to remove the contaminants from the system. Initially, we do separation. So we’re going to remove any sort of liquids that we can get out with like standard gravity separation. It’s usually pretty simple. Then we like to do dehydration, which will remove the water vapor so that you don’t freeze up going to other equipment. So when you try to take pressure drops or something, you’re not going to turn into a big old ice cube inside the pipe, outside of the pipe. Sometimes it just happens.
Chris Smithson:
If you take a big enough pressure drop, the pipe is just going to get cold if it’s not insulated. But if you try to take that pressure drop and you get too cold, you’ll freeze up internally. Then we like to do BTU reduction just because normally we’re doing that using the cold that happens from the pressure drop to cold separate that stuff out. And then we send the field gas at… We have pressure reduction and we send that to the engine. So that’s the typical steps that we like to do to get that gas cleaned up for the engines.
Cameron Croft:
For the separation section, it’s not just separation of like let me throw a separator out there. So kind of do go into specifics of gas/liquid separation, coalescing filtration, what actual separation means and the different variables.
Chris Smithson:
Yeah. So not all separators are created equal, generally based on their size. Most of the time they are just big empty vessels with some internals to help with the initial deflection of the liquids and then like miss elimination at the top. But a little 16-inch separator. If you’re doing 8 million, that’s not going to stop liquid. If it’s too small, the liquids will just continue through the separator.
Chris Smithson:
They don’t even need to really get the liquid very high. It’ll just still go through the separator. So probably sizing that. Especially, you should always try to give yourself some protection against slugs. I mean, if they put a pipeline in and they weld that, they have to hydro test that. If they forget to take the hydro water out or properly get a lot of that hydro water out, that hydro water is going to come to you as soon as you try to turn that fuel line on.
Chris Smithson:
And if you can’t handle 40 gallons of hydro water or 50 barrels of hydro water, then all of a sudden you have a big problem. So you can never go wrong with too big of a separator. But separation is really important initially to really make sure that it gets out there. And then a coalescing filtration is really good to make sure that any sort of mist or particulates don’t continue on through the rest of the equipment.
Chris Smithson:
If your gas is cooling and it’s really rich, you’ll actually get like a fog inside the pipe that is natural. It’s hydrocarbons. They’ll eventually condense into a liquid. But if that fog will go right through a separator, it’ll try to get knocked out in the mist pad that’s built into a lot of separators, assuming your separator has them. But coalescing filters are typically designed to coalesce that stuff out of the gas.
Chris Smithson:
They’re not just particulate filters. They are much higher end. Usually we go with the sub-micron filter on that. Having good filtration can really protect things downstream from other problems, frac sand, other things like that from getting into other places they’re not supposed to.
Pressure reduction, gas heating control
Cameron Croft:
I’m sorry. I’m answering a question right now on the H2S levels. So like coalescing filtration. And then this actually leads into the question I’m trying to answer right now is… Oh. That is right. So the next step, I know this wasn’t part of the big concept block, but do go into this, the pressure reduction, gas heating control section.
Chris Smithson:
Yeah. So pressure reduction is normally handled through like a control valve. Especially sat the higher volumes, you want control valves. You just don’t want to stack up a bunch of those big Joe regulators. Having a proper control valve will give you finer tuned controls. On the smaller systems, those big Joe’s work just fine. But they do have a volume limitation that you eventually start to hit.
Chris Smithson:
But pressure reduction was where you’re going to risk getting cold. And when you chill the gas, if it’s richer gas, that’s when you risk liquids falling out and stuff that was a gas now has liquids coming out of it just because you drop the temperature 20 degrees. So it does depend on the gas, if there will be liquids falling out of it. But anytime you have a pressure reduction, you have a risk of liquids coming out.
Chris Smithson:
If the gas is clean enough, that won’t be a problem, but that’s where it would happen. If the gas cools down, you might have liquids. So having separation after pressure reduction can be helpful. At least the bleed line, like a little bleed valve or something on your line just to make sure like if you have this built in to a fuel system. Once you’ve done a certain amount of separation and pressure reduction, if you’re just like going down to like 50 PSI to 20, then it’s not really going to matter because we’ve already done the cooling part of it.
Chris Smithson:
But that initial pressure reduction, that’s where your risk of gas heating can be important because of that cooling. If you cool down too much, if we heat it back up, then liquids can’t fall out again, assuming we don’t cool down to our ultimate lowest temperature that we achieved. But yeah, gas heating can be important to really make sure that you are way above what we call hydrocarbon dewpoint, the temperature at which liquids will form in the pipe. So if we heat it up enough, we’re going to be way away from that and that risk has then gone. You can take all pressure drops you want and you’re not going to have that problem anymore.
Cameron Croft:
So once you do the separation, pressure reduction, gas heating, you’re getting it back up to the level. The next thing is removing the water from our concept. So we utilize heavily on the passive dehydration system only because it’s easy. You switch on the valve and you’re ready to go. And that seems to be working very well with, I guess, trying to stay within the scope of work of operations of…
Passive dehydration systems for Field Gas
Cameron Croft:
We have glycol systems. We lease and we sell those things. But trying to get someone experienced enough to get them kicked up, started up, circulating, changing out the filters and having a good understanding. It’s a little bit more effort than what’s necessary. But kind of go into the passive dehydration systems.
Chris Smithson:
Yeah. I mean, I don’t want to dive too deep into it. But basically our passive dehydration systems versus other ways of the hydrating gas, ours can handle start-stop flow. You can turn it off for 10 minutes, turn it back on for 10 minutes, turn it off again. Our PDS system, it can handle that with no problem. Usually the valve just gets shut and then you open the valve and flow happens again, you shut it off.
Chris Smithson:
Our units handle that better than any other dehydration system that we’ve seen on the market. So like glycol systems, if you ever heard of them or used them, they’re complicated. They have pumps and burners, and they have to be start up every time. If you’re on one hour frac stages and you’re shut down for 30 minutes and an hour again, you don’t want to be restarting that. And starting and stopping flow on certain systems can create problems with them, carry over issues or other issues with them.
Chris Smithson:
So our passive dehydration system is really good at just drying the water out of the gas so that it doesn’t create freeze ups and that moisture isn’t in your field gas, isn’t creating corrosion or anything else down the line. But mainly you’re not freezing up. That’s the main thing, is just dry it out, get all that water out of it, all that water vapor out of it so that you don’t have those freeze up problems.
JT Systems for Treating Field Gas
Cameron Croft:
Well, right after the dehydration, you remove the water. So you decrease the probability of a hydrate formation. The next step was the BTU reduction. I know we have links. And for all those that are actually paying attention to it, we’re going to have links in all of our YouTube channels. So if you want to know more about a specific product line, you can definitely go to it. But do explain a JT system to us.
Chris Smithson:
Yeah. So basically we take a big pressure drop. So this is why we like to have that real high pressure, like 1,000 PSI pressure. Because we’re going to take like a 600, 900 PSI drop, whatever big drop we can get. We’re going to get cold safely inside of our system and we’re going to use that cold effect to cold separate out the heavy stuff that’s causing you the BTU problems on your gas.
Chris Smithson:
And we have heat exchangers and cold separators and control valves and the pressure regulators on them to do that. But basically, we chill the gas, we cold separate out that heavy stuff. And then you get a lower BTU gas on the outlet, but also more consistent gas on the outlet. Because just temperatures can make the BTU go up or down. Like you were getting the gas at a hundred degrees, and then it’s really hot now and now you’re getting your gas at 120 degrees from the field.
Chris Smithson:
That gas may now be a higher BTU because it’s hotter, because it can hold more of the heavier hydrocarbons. The JT gives us the opportunity to kind of even out those swings in BTU so you get a more consistent quality field gas into your fuel systems.
Cameron Croft:
That was a duplicate. So the next thing was the gas conditioning equipment options. So these are the things that you have highly recommended it. I’ve heard you on enough conference calls and video conferencing, that you’re always kind of pushing this hard because it’s better control, better redundancies built in. But do explain why you always recommend this.
Chris Smithson:
It’s basically visibility of data. Transmitters are expensive. I mean, those little $2,000 transmitters start to add up pretty quick. But being able to see your pressures and temperatures, having a gas meter that is basically a little computer that you can plug this stuff into, that you can start doing conditional logic where you say like, oh, if this pressure gets too low, alert somebody, warn somebody.
Chris Smithson:
That way they can come fix it before you have like an emergency shutdown or something. Having emergency shutdown valves was good. High-level kills. If your separator gets overflowed, being able to shut that off and shut a valve so that the gas does not continue with that liquid into your fuel system. Really good. They’re options. You don’t necessarily have to have them. You don’t need it until you do need it, right?
Chris Smithson:
But all that combined with remote monitoring and you have a full solution where you can just look on your phone and you can see… And even if it’s on the other side of the pad, you look at your phone and you can see what’s going on. You don’t have to walk over there and check on anything. But yeah, they’re good options. But yeah, it’s basically just visibility. Being able to have that visibility into what’s going on on that equipment so that you can troubleshoot it.
Chris Smithson:
Normally we are not at our equipment. So our goal is to put those equipment out there that we only need to show up for a move. And this equipment, once started up, it will run and do everything it needs to for a month. And then we’ll come by once a month or during the move to handle it. So this isn’t 24-hour operation equipment. It’s designed to run unoperated for a month, maybe with some visibility, just walking around, making sure there’s no leaks or anything. That things are within where they’re supposed to be. Having this visibility definitely lets us get warnings ahead of time before something happens.
Cameron Croft:
We’ve done enough times where that continuous improvement of… Because you are going to get bumps and bruises along the way. There’s going to be failures. There’s going to be liquids or all of a sudden liquid slugs hitting us, BTU changes. And then these little call-outs that you’re always putting on, the alarms, it really does help out the redundancy of a shutdown.
Cameron Croft:
Because the last thing you want to do is have at any stage, it goes to the processing and it didn’t process. And then now you’re hitting a million dollar per engine equipment. It’s just kind of a hard thing to swallow at that time. I’ve heard you enough times talking about these ad-ons and you’re always pushing and we’re trying to educate the clients and the operations as much as possible. It’s still their decision. But it seems like a lot of people are turning into it right now. We can’t have a failure mode. We got to have these things added on.
Cameron Croft:
This is backwards. So that’s equipment options. That slide should have been before the other one. It’s been an hour. We’re going to go ahead and wrap up. So this is my contact information, company contact information. If you have any specific questions that you didn’t answer on this or you have someone else that wants to set up a conference call with Chris and kind of get this thing started, scenarios, we’re here for you. That’s the reason why we’re doing these things.
Conclusion
Cameron Croft:
So please reach out to us at that time. You can go through the company, which will go to one of our sales reps, and then they’ll get with Chris, or you can reach out to me directly. Now, free hat or shirt. So you will get a survey email. This is the only way that we know that we can get better, that continuous improvement and how to tailor and improve these upcoming webinars. And if you have a webinar idea, please put that in the comments.
Cameron Croft:
If you want to see this one of the comments that we received as they want to go more into natural the triethylene glycol clean-out. So that was a fantastic one. We’re putting that webinar together right now. If you need a professional development hour, reach out to us so that way we can shift you that paper for one hour so you can add it to your continuing education.
Cameron Croft:
If you have any questions, again, reach out to us. Check out our resources. We got a lot of videos, a lot of other webinars. This is our 15th webinar we’ve done. And then we have specific product line videos as well. So appreciate everybody for joining us. And then Chris, thank you for taking the time and talking with us.
Chris Smithson:
Yeah, no problem.
Cameron Croft:
All right. Take care everybody.
