In this SPE Tech Talk with Estis Compression, Joe Sinnott and Will Nelle discuss how high-pressure gas lift gives oil and gas operators the ability to meet aggressive production targets without sacrificing reliability.

Transcript of the High-Pressure Gas Lift SPE Tech Talk

0:00:35.9 Joe Sinnott: Welcome and thank you for joining us today for this SPE Tech Talk with Estis Compression. I'm your host for this broadcast, Joe Senate coming to you live from Pittsburgh, Pennsylvania. And I'm excited to once again dive into some innovative technology that is challenging the status quo in our industry. Today that technology is high pressure gas lift, and sometimes you call it HPGL, and it is a game changing artificial lift methodology that replaces failure prone down hole ESPs with special surface compression equipment. High pressure line gas is injected down the tubing and deep into the well producing up the annulus. This means that 100% of the lift system is on the surface. We're joined today by Estis compression to discuss how high pressure gas lift is giving oil and gas operators the ability to meet aggressive production targets without sacrificing reliability, all while lowering maintenance costs.

0:01:37.4 Joe Sinnott: And if all of this sounds too good to be true, then we encourage you, the audience to take advantage of this live broadcast and ask today's expert how everything I just described is possible. So please use the comment section to share your questions, your opinions, your skepticisms about today's topic, and we'll get to as much of your input as possible later on in the show. Another great way to provide input and get involved in the show is to let us know where you are watching from today and to answer today's audience poll question, which is, what factor is of greatest priority when selecting an artificial lift method. A, reliability B, cost C, ease of use, or D familiarity. Let us know your answers in the comment section and we'll take a look at the results later in the show with our guest.

0:02:29.7 Joe Sinnott: And speaking of our guest, let's go ahead and introduce Will Nelle, Director of Technology and Innovation for Estis Compression. Will leads the company's technical services group and is responsible for driving innovation and technology development within the company's product line and culture. He works closely with the sales operations and manufacturing groups to develop equipment for the industry that uniquely addresses the customer's unmet needs. Will has 21 years of experience in the oil and gas industry, and as a member of SPE and SWPSC, he holds five patents and has published three technical publications. He graduated from LeTourneau University in 2004 with a degree in mechanical engineering and is joining us today from the Permian Basin. With that, hello Will and welcome to SPE Tech Talk.

0:03:24.0 Will Nelle: Yeah, Joe, good morning and thank you for having me. I appreciate the invitation and thank your audience for joining us this morning.

0:03:31.5 Joe Sinnott: Alright, well we are all excited to have you here and I guess to kick things off for our audience, for myself selfishly, can you begin by telling us the basics, you know, what is HPGL?

0:03:42.4 Will Nelle: Sure, Joe, great question. HPGL, well, it's simply an acronym for high pressure gas lift. High pressure gas lift is an artificial lift method. It is a variation on gas lift, which many in our audience are familiar with, but it's really a hybridization of a couple of different forms of gas lift. So most people are familiar with conventional gas lift. Some may be familiar with annular gas lift and high pressure gas lift just marries those two and take some of the good points of each of those into one process. So let me describe real quick conventional gas lift is where gas is injected down the annulus. In other words, the space between the production tubing and the wellbore casing, and it travels down that annular space and is injected into the tubing at one of multiple different lift points. Or some people might know them a gas lift valve. Switch gears real quick to annular gas lift and we kind of reverse the flow to where gas is injected down the tubing and flows up the annulus. Also transitioning between those spaces through a gas lift valve. Well, high pressure gas lift takes the flow of the annular gas lift flowing down the tubing and up the annulus, but does it through one single point, in other words, not multiple gas lift valves, but really goes through a single point and that single point is the end of the tubing.

0:05:16.4 Joe Sinnott: Got it. So I don't wanna just take your word for it. I know our audience, our technical audience won't just take your word for it. So can you give us a little bit more detail? So how does that work? So you explained the setup, you gave a little background. So how does HPGL actually work?

0:05:31.3 Will Nelle: Sure. Well, the beauty of high pressure gas lift is that it's so simple really, you know, I mentioned that we are taking away gas lift valves and we are injecting down the tubing, injecting down the production tubing. In order to do that, we have surface compression, which takes gas from an operator's, say a central tank battery or a gas gathering system, and it pressurizes it to a high pressure as the name suggests, injects down the production tubing, goes all the way to the end of the production tubing, and then injects gas bubbles up through the fluid column at the end of the tubing. So different from conventional gas lift, different from annular gas lift, we are injecting from day one around the end of the tubing, deeper into the well, we have no moving parts. We lighten the fluid column from day one from the very end of the tubing, and ultimately providing the most beautiful part is providing a lower bottom hole pressure very, very early in the life of the production method.

0:06:44.6 Joe Sinnott: Nice. All right. Well thank you for giving the explanation. Again, thank you for all the details so far. I wanna remind our audience, again, we have a technical expert here, in fact Will correct me if I'm wrong, but I mean, you are the man on this, right? You are the genesis behind the technology that we're talking about today. So, whether or not that's actually true, we're gonna assume that for our audience. So audience ask questions, share your comments, any curiosities you have about, again, how this works, why it works, throw it in the comment section. We'll get to as many of your questions as possible later on in the show. But for now, I got plenty of my own questions. Of course, Will. So I guess moving on, you know, you gave us a basic understanding of things. Tell us when, when do you use this technology? When does it make sense to implement HPGL?

0:07:27.4 Will Nelle: Sure. Well, the beauty of high pressure gas lift is, is so versatile and so flexible and really can be used in many applications. However, there are some instances where high pressure gas lift really shines. And that is in unconventional production, which most of us are doing these days, right? Unconventional production all over the US it has been used prolifically all over the US. We've had 1600 installations across the continental US and all of the different major oil and gas place. But the installations that it tends to provide operators the most value would be early in the life of the well, when high fluid rates are needed, high fluid lift rates are needed, and a second one that is close behind is dealing with frac wells, or in other words, when you have a well that has received fluid from an adjacent well that has been fractured.

0:08:27.4 Will Nelle: In both of those instances, there are large volumes of fluid that need to be lifted and HPGL just really shines in those instances. The thing that too, I would clarify and add some more detail about the unconventional production is when there are high GORs, right? Which is present in many of the unconventional reservoirs. And also when there are heavy solids, which we also see in unconventional reservoirs, right? We inject sand into our frac fluid to help prop open the fractures. And HPGL really shines in those applications.

0:09:08.5 Joe Sinnott: Great. Well, again, I'm sure all of our production engineers are excited about everything that this technology promises, but I also know our audience and I know that there's always a question of value. So can you shed some light onto, you know, the ultimate value of this technology once it's implemented Will?

0:09:26.4 Will Nelle: Sure. Joe, this is really my favorite part of talking HPGL. I think you proposed earlier that HPGL seems almost too good to be true, and I've said that for years as I have talked through HPGL, it's almost magical. And so let me share through some of those. This diagram that we have up on the screen, I think illustrates some of those very well. First of all, the a point I would make is that a high pressure gas lift by virtue of taking jewelry out of the well bore, right? We're not doing gas lift valves. HPGL is a competitor enlarge to ESPs. So we're taking complex electrical devices that are large bore and can fail. We take those out of the well bore, and in doing so, we can put the production tubing lower into the well bore than we can other artificial lift methods.

0:10:25.3 Will Nelle: So if you will look at this diagram, normally our kickoff point, which in this case is shown at about 7,400 feet, is the point where we would seize putting ESPs or gas lift valves. However, in high pressure gas lift installation, we can put that tubing lower and we can see that shown at the perforated sub at about 8,050 TBD. So in this case, we can put the lift point of the well a whole 600 feet lower, which allows operators to lift from a lower point to lighten the fluid, the entire fluid column, and to lower the bottom hole pressure lower than it would be otherwise. So that's the first point I would make on the value of high pressure gas lift. One that we touched on a little bit was taking jewelry out of the well bore, right?

0:11:25.6 Will Nelle: Anything that is put into a well bore is subject to failure. Gas lift valves are subject to failure. ESPs are certain for failure, orifices, anything that can go downhole in order to repair it, the well would have to be pulled, right? So it requires a pulling unit, it requires downtime. High pressure gas lift is so simple, right? There's really nothing to fail. And Joe, you brought it up earlier in the presentation that all of the problems are left at surface. So we see very few problems with the compression system that is used to pressurize the gas, but when those inevitably occur, the problem can be dealt with on the surface. There's no pulling unit, there's no work over rig, really, the compressor can just be dealt with and get back online in minimum time. So I would say that we don't have to worry about fishing the downhole tools.

0:12:34.2 Will Nelle: Further we just see a larger runtime. The non-productive time is very minimal. We see high runtime from high pressure gas lift installations. One of the most beautiful points that I think operators will appreciate and appreciate the most is that it is a lower cost artificial lift method. ESP is beautiful in that it lifts the high fluid volumes, the high fluid rates that everyone loves. However, ESPs struggle with gas, ESPs struggle with solids. And when we know that those are present in unconventional reservoirs and we put in an artificial lift that's challenging with both of those times or both of those problems, it kind of doesn't make sense. And that's where HPGL shines is that it is tolerant of solids, it is tolerant of gas and inherent to its name, right?

0:13:44.5 Will Nelle: High pressure gas lift needs gas. And so ESPs, when it fails from those problems, really has to be pulled out of the well. So your well is down, you're not producing the oil and gas that you want to produce, plus you're incurring rig costs, you're incurring repair costs for the ESP. And all of those add up really, really quick such that HPGL competes very well against ESPs. And I would have you transition to the next slide and to help oil and gas operators see the value proposition, because as I mentioned, it seems too good to be true until you put a pencil to the paper and you really work out those numbers. So we have developed an evaluator to allow people to enter the costs that are incurred by using an ESP and enter the costs that are incurred in an HPGL installation. And then it just crunches the math. And so here, case in point, we see a very typical scenario that lease operating expense per well of an ESP can be, in this case, $630,000. A similar HPGL installation would be 375. When we talk about the capital cost, when we talk about the operational expenses, and then when you compare those, we see a discount commonly of 30 to 40% of HPGL over ESPs.

0:15:25.4 Joe Sinnott: Well, I got to admit, Will, I'm sitting here still thinking, yeah, you know what, this still seems too good to be true. So I guess what are there trade offs? I mean, are we talking different rates versus ESP? I mean, who, again, I'm gonna play the role of our audience here and play devil's advocate. You know, what am I missing here? What's our audience missing?

0:15:43.5 Will Nelle: Well, sure, and Joe, you're not missing anything and I think that's why we're out here to talk about it. In fact, I would go so far to point the audience to an SPE paper that I co-authored back in 2018 to compare and to show real world examples of production of high pressure gas lift versus ESPs and show that they are neck and neck. And in some instances we've seen that the high pressure gas lift fluid rates can even exceed ESPs. So we've got lower failure, we've got lower cost, we've got the same or better fluid lift rates. Again, I would really propose that it's just, it seems too good to be true, but we're not seeing that in the data. And we've published on that just to give users of high pressure gas lift a real world case study.

0:16:41.4 Joe Sinnott: Great. All right. Well, audience, you heard it. Check it out if you're skeptical at all. You mentioned a couple things just now, just kind of ticking off, you know, the motivation obviously for having artificial lift, which I think is a good segue back to our poll question from earlier in the show. So earlier we asked the audience what factors of greatest priority when selecting an artificial lift method A, reliability, B, cost C, ease of use, D familiarity. Seems like the majority of people watching on energy stream LinkedIn have chosen reliability, A. So I guess let me throw it back to you. Are you surprised by that answer? What do you hear from operators? What's your take on the answer to that question?

0:17:18.9 Will Nelle: Yeah, it doesn't shock me a bit, Joe. And in fact, that's part of the beauty of high pressure gas lift and we believe in it. I'm not here just selling something to try to make some money out of it, right? I'm talking about this because it aligns with what we see that the industry and the market is really after. People want technologies. People want artificial lift and production methods that help them to achieve this reliability. And that is just the beauty of high pressure gas lift is that it is, it is so simple and it is in turn so reliable.

0:17:55.6 Joe Sinnott: Got it. All right. Well, thank you for that. Thank you so far for all the information for anybody tuning in just now. You've missed a lot of promises here that Will has made. And I encourage you if you're hopping in now, you can always go and start from the beginning. But I guess one thing, you've mentioned simplicity a couple different times, and we have one question from Kurt who's watching on Energy Stream. Just to confirm here, are all the moving parts on the surface. Kurt, thank you for the question. Will, what do you have to say there?

0:18:24.0 Will Nelle: They are, Kurt, and I appreciate your question. And again, that's part of the uniqueness. And the value, the beauty of high pressure gas lift, there are no moving parts downhole. Now, admittedly some people still choose to use an orifice or a gas lift valve, and certainly each operator has to choose what they are going to do individually, but I would suggest to you that many, many other operators are using no valves, no orifices and going around the end of the tubing or using a perforated sub, both of which are non-moving parts, and there's really nothing to fail so many, many operators, many installations of high pressure gas lift do indeed have no moving parts, really nothing to fail downhole.

0:19:17.5 Joe Sinnott: Alright. Well, it doesn't get much simpler than that. Alright, moving on, we got some more questions coming in here, this one's a two-parter from LinkedIn. Later on in the life of a well, when lower bottom hole pressure is needed to produce the wells, is the HPGL configuration still the best option? And as a follow-up, is there a sweet spot where it is preferred to move to the conventional gas lift configuration, Will?

0:19:42.9 Will Nelle: Sure, that's a great question Mauro. And I appreciate it. Many people ask that to us, and what I would say high pressure gas lift real value proposition is in lifting the high fluid rates that we see in the initial life of the well, competing with ESPs, however, high pressure gas lift can be configured or modified a little bit later in the life of the well, as the fluids are unloaded as the well starts to decline, so rather than flowing down the production tubing and then up the annulus. Gas can be injected down the annulus and up the production tubing, which decreases the cross-sectional area, it decreases the flow rate, the gas injection rate from the compression system for the high pressure gas lift system, so you still get the value of no moving parts, but one lift point, and that lift point being very deep into the well, and so we commonly see operators setting their well heads up to where they can configure and flip-flop the injection from the production tubing to the casing.

0:21:00.0 Joe Sinnott: Great, I guess I'm kinda building on that in terms of configuration, is there a typical HPGL set up? Are there specific considerations that operators would need to have in mind if they were to go down this path, Will?

0:21:13.9 Will Nelle: Sure, well, I don't know that there's anything typical in the industry, we're all a bunch of cowboys and we like to do our own things. However, I would say that over the years that we have watched and operators implement this and we have made our own recommendations there are maybe some best practices, and so I would say, first and foremost, configuring your wellhead such that the gas from day one can be flip-flopped rather than saying, Gosh, today I'm injecting down the production tubing, and then tomorrow I want to inject down the casing but in order to do that, I'm gonna have to shut in my well, I'm gonna have to go re-configure my wellhead. Plan on it from day one to make a configuration. I would say also in the environment where we have multi-well pads, manifold those wells together to where you can have one or two high pressure gas lift compressors that would feed multiple wells, because the reality is as high pressure gas lift or any artificial lift is used, and the well declines, and then the artificial lift method is not used or not needed day in and day out, it may be needed only when there's been a shut in period, so you can be very efficient in using one high pressure gas lift booster compressor among multiple wells, which allows the operator to be more efficient, more cost-effective.

0:22:48.3 Joe Sinnott: Got it. Alright, well, thank you for sharing that it's funny. You talk about us being cowboys in this industry, but we are cowboys who are very focused on safety, of course so.

0:22:56.6 Will Nelle: Sure.

0:22:56.6 Joe Sinnott: I think maybe that's a good segue to say, Hey look, Will, we're talking about high pressure, we're talking about newer technology, we have a question that's come in here on LinkedIn from Omar related to safety. So can you talk about safety considerations as it relates to HPGL?

0:23:12.5 Will Nelle: Yeah, you know, it's a valid question because all of us wanna go home the same or better. We have families that we wanna get back to, and we value our lives and the safety of it. And I would say, of course, high pressure gas lift is safe, but to get into some of the detail in the name where we say high pressure, that raises eyebrows and people think, Oh, I don't like that, but I would remind users that high pressure gas lift is really operating at but a fraction, 50% or even 30% of hydraulic fracturing pressure so high pressure gas lift on the high side operates at 5,000 PSI more commonly. Day-to-day we see 2-3000 PSI fracture pressures get up to 10,000 or 15,000, so the safety standards, the processes, the equipment exists to deal with the pressures. Does it make sense always to be aware to do your has-OPS, to do your analyses and to review it as you switch from conventional to higher pressures, of course, but does the technology, does the understanding exist to be safe? Absolutely. And in my seven years dealing with high pressure gas lift, I've seen no catastrophic failures.

0:24:36.9 Joe Sinnott: Great, and again, you talk about obviously your familiarity with this, my understanding is, again, I said earlier, you're the man on this, can you give a little bit of insight on how you got to this point? Again, you don't have to share the proprietary stuff necessarily, but can you talk a little bit about the evolution to go from obviously a need in the industry to have all these benefits, but can just give a little color for our technical folks out there who see themselves as innovators and maybe strive to creating game-changing technology like you all have here in front of us.

0:25:11.0 Will Nelle: Sure. Well, it's been an interesting journey to watch. High pressure gas lift has been used for many years. We talk about it being kinda new onshore, and while that's true, it's been used offshore for many years, I wish I knew the people who kind of invented, if you will, such a novel and novel because it's so simple process, but these were done many decades ago, and really it's come onshore, a couple of the changes, the innovations that have allowed that would be that higher pressure casing ratings due to hydraulic fracturing, that would be one that the wellbore integrity is high and is set up for high pressure. The other thing that has been present is the advent of high pressure compressors, back up a decade ago, high pressure compressors were not available in the industry to be able to accomplish high pressure gas lifts. They're not commercially available, but CNG compressed natural gas for vehicle refueling has helped to bring about compressors to do that, so you take the wellbore pressure rating being higher, you take the high pressure compressors and you take a few sharp minds and said, Hey, you know, we could do this thing, onshore that we've done offshore.

0:26:37.7 Will Nelle: Commercially, it makes sense. Technologically, it makes sense. And so I would say within, this really started hitting the ground late in 2016 and 2017, and it has just grown exponentially in that time period.

0:26:54.5 Joe Sinnott: Great. And I guess here you talk about the evolution and looking forward, we have a question that maybe ties into that here from Scott, and Scott says, how do operators need to change their intermediate casing designs to utilize HPGL are the limitations of casing and remediation as needed later in the life of a well. So I guess maybe my question is building off of Scott's to take full advantage of the technology that you've described, all of the promises are their design considerations that operators should be thinking about to maybe tweak things so that they can not just settle for all of the promises, all of the results that you've talked about, but make sure that they're in the best position possible to take advantage of HPGL.

0:27:36.3 Will Nelle: Well, that's a great question, and Joe, the neat part here is that the casing design that you're already using that accommodates the fracture pressures that exist in unconventional production today, accommodates already the high pressure gas lift process, but I would say that operationally now that the wellbore fluids are coming up the casing, the annulus, between the production tubing and the casing, corrosion protection needs to be a consideration to operators. A lot of people have asked, "Well, and am I gonna fail my casing? Am I gonna have casing problems?" And we've not seen that to be the case, but I believe a lot of that is because people realize that. They realize it upfront, and so they implement casing, corrosion protection programs. And I would definitely encourage that.

0:28:32.2 Joe Sinnott: Great, alright. Well, I guess as we move to conclusion here, are there any other considerations? Are there any other things that you want our audience to know who again, especially if you just tuned in here in the last couple of minutes, you may have missed all of the magical promises, all of the results that you've seen from HPGL. Anything you wanna tell our audience here as we move to conclusion here, Will.

0:28:54.9 Will Nelle: Well, I would just encourage the audience to be open-minded. Again, we've proposed that this is too good to be true, and in my estimation, it really is. I've watched this over the time period, we love an opportunity to introduce folks to this and then to give it a whirl, to give it a try. Joe.

0:29:19.1 Joe Sinnott: Great, alright. Well, you heard Will there. Give it a try, be open-minded and if they are open-minded or have some additional questions, Will, and want to get a hold of you, what's the best way for them to contact you?

0:29:30.9 Will Nelle: Sure, Joe, I appreciate that, you can reach out to me via LinkedIn, in there will be my company email, we would love to talk to you about this and to answer any questions or to introduce you to this amazing artificial lift method.

0:29:46.8 Joe Sinnott: Great. Well, thank you again for all the information, for all the enthusiasm for shedding a little bit of light again on what a true innovator our industry does and the results that operators can see and can benefit from. So again, thank you to you, a special thank you, of course, to Estis Compression. Special thanks to our audience who ask plenty of questions, more questions than we were able to get to today, but I encourage you to keep asking questions, even if you're watching this on replay, keep the conversation going on LinkedIn because that's the beauty of this format here is that the conversation doesn't have to end right now, that being said, if you do wanna watch a replay of this conversation, you can head on over to the SPE Energy Stream, the industry's digital pulse visit streaming.spe.org. So once again, thank you to the audience. Thank you to you, Will. And hope everybody has a great day and I'm your host, Joe Sinnott. Hope you all join us again next time right here on SPE Tech Talk.

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Get ahead of the trend

While it’s been used offshore for decades, HPGL is still considered a new technology for onshore artificial lift oil production. Yet single-point HPGL is the simplest, most efficient and productive lift system with the lowest total cost of ownership and the least downtime.

With companies like Estis making wellhead compression affordable, customizable, and reusable, using HPGL for onshore production is ready to take off. If you’d like to take advantage of this emerging trend, contact us to see how you can improve your productivity and reduce costs.