Welcome to the official Erdos Miller Podcast, where we spend our non-productive time talking about drilling tech and getting the latest insight from industry leaders on our show. I'm David Erdos, and today I'm solo and filling in for Ken. Today we brought an industry leader and a friend of ours from Packers Plus, John Leitch. Welcome John.
So John, I don't know how much you know about us, but most of our work is on the drilling side or my experience specifically is on the drilling side. So completions is kind of a big unknown, mysterious world to me, but why don't we start off by asking you what your background and industry is, kind of what your career trajectory has been?
Okay. So my history in the oil field started back in the early '80s. So there wasn't too much advanced completion systems out there back then. So I was working on permanent gauge completions, memory production logging, memory gauge data, and it progressed into permanent downhole gauge type completion. So this is giving the operator real time data from in the well, normally just write out the reservoir sections. So that was pretty advanced back then. Since then, the completion systems have got more advanced. And with that, they require a lot of data. So pressure, temperature data at ideally every zone that they have in the well.
So the completion systems have advanced over the years. The way I really got more into the completion side is back in '95, I joined a small completion company in Aberdeen, Scotland called PES, which was Petroleum Engineering Services. And what these guys hired me on to do was ideally it was to teach them how to get one of these completion type systems in the ground and to look at all the issues that we might run into in terms of when you're running cable, you're running a lot of complex completion equipment, making sure that we've thought about what might go wrong and mitigate that by taking steps to ensure that things go okay.
So that was my early part. So the thought was that I was going to teach them how to run it in the ground and do that operational side of running the equipment as well. With that, I ended up having to spend a lot of time in the US learning what the system was going to look like. So I worked directly with the electronics engineer, the mechanical engineers. And as we started building the system up, it became obvious that I needed to spend a bit more time in the US on the system as the operational of it for me was actually quite a relatively easy and still some fairly advanced equipment was already out there available. So mine was more to learn what this system was going to be like.
So this was going to be the first intelligent completion systems being run. So the company, PES, ended up being taken over in the late '80s by Halliburton. Not long after that, Halliburton went into alliance with Shell and that was where a company called WellDynamics came up from. So it was a joint venture. So there was input from both companies getting the intellectual property passed between both.
So I was spending a lot of time in the States trying to learn how the system might go. I spent a lot of time actually doing the mechanical testing, the electronic testing, building circuit boards, testing circuit boards. And eventually we got to the point where we built the first prototype system. So we had a... It was a Tucson system that we had back then just for a initial test. And what we did is we took that to a test well in Aberdeen, just outskirts of Aberdeen, and we put this system in the well to prove several things. To prove that the system would work in the test well that we had and also to prove that we had the operational steps in place to be able to run something as complex as this was thought to be back in those days.
So could you define for us what intelligent completion systems are?
Okay. So intelligent completion systems are traditionally thought of being something where you have control of a valve in the well and you also have the pressure and temperature monitoring for each of those different zones that you want to have control over. And this is all controlled on surface. There are several ways of doing it. Some use hydraulics for the mechanical control of the valves downhole, others use electrohydraulic, and more recently full electric is now the way that a lot of operate companies are actually going.
Okay. And so to somebody like me who's not familiar with completions, why do you need these valves downhole?
Completions now have got to the point where they need to get a little more complex because the operator doesn't just want to produce from one particular reservoir zone. He might have three, four, five, potentially even more that he wants to control individually. So some of these subsea wells, if you start producing water from a specific zone, you can very quickly fill your pipeline up with water and actually start to kill off your well. So when they start producing water, the first thing they want to do in most cases is shut last in. So when they find water coming through on surface, they can actually then close the valves individually and then isolate that water zone, so keeping their production at the higher levels.
So you basically have the well broken up into different zones and these valves that you can isolate and separate these zones and just pick and choose which zone you want to produce from. Is that kind of the basics?
Yes, that's exactly it. Yes. So each zone is isolated on the valve size, but with a downhole packer. So basically big rubber element with slips anchor, anchor to the casing or in some cases it's a little different when you're going into open hole, but typically it's normally in case holes is where most of these completions have actually been run.
Okay. And so you were just getting into how these systems are controlled and what advances have been made. Can you elaborate on that a bit more?
Yeah. So the early ones were quite large and quite costly to develop. So the early one that I worked on was an electrohydraulic system. So what we did is we used the hydraulic line going from downhole all the way to surface for the actual mechanical force that we needed controlling that with solenoid valves. And then on the electrical side, that did our communications and control along with giving us pressure and temperature gauge data.
Okay. And so you have a wire running all the way from surface to these electrical systems so you can talk to them or [crosstalk 00:07:31]?
That's correct. Yeah. So the system that I worked on back then with the PES and WellDynamics actually had a duo system in there. So it was duo electrical and duo hydraulic. So it gave that redundancy. So in case one line broke, you could steer from one valve to the other one and then get back. So you had the redundancy of the system, the big thing being when you stick this in the well, it's going to cost a lot to put it in, but if it goes wrong and you lose that well, it's very costly if you have to pull those completion systems out. So having that control and reliability is really critical on intelligent well systems or intelligent completion systems.
Right. So what is the expected lifetime of one of these systems?
That's a good question. If you talk to most operators, they'll say that they want 20 plus years. So I was coming from the drilling side, making something that's going to last 20 years, you've got a lot of testing to do and you've got to use some very high-end components and you've got some high-end testing to get involved with also.
Right. That's something we're completely unfamiliar with. Drilling a well might take a week or two and then you're done. Certainly not years. And so what are the biggest challenges these days that you've seen in advancing these intelligent completion systems further?
Yeah, so the early days, the quality of electronics we could get was not what it is nowadays. So most of the components went in those were military-grade stuff. So really only 125 degrees C-rated parts. And they were very... The components that we were also using they were very power-hungry. So we had to have a lot of power being pumped down the electrical line to these systems. Nowadays it's advanced to the point where as Erdos Miller's aware, a lot of the companies are now using hybrid electronics or variants of hybrid type electronics. So like the packaging, it gets a lot smaller, the reliability goes way up and also the high temperature rating of these components goes way up as well. So 200 degrees C operating systems is now quite standard. Most of the early stuff was all analog type electronics, very little in the digital side. And since then, it's now gone to the digital electronics side.
Okay. And so what are the kind of the... Looking five, 10 years into the future, how do you see intelligent completions advancing? What's next?
What's coming next is really all electric systems and all electric with a little power. So where things were in the early days, the subsea interface cards that would put all the power of communications and control down the hole, we had a higher power budget back then in the range of 400 or so watts and potentially even more for some of the systems that were out there into the 1,000 watts was required to be pumped downhole. The way a lot of the subsea companies are going now is their trees, subsea trees are actually requiring or requires to use much lower power requirements.
So there's a standard out there called IWIS, and they have power limits depending on the type of equipment you put down an hole. So they'll have low, medium, and high power, high power for them being 96 watts, which is not very much when you've got to control some downhole motors and other things like that. The earliest systems that were just requiring communication and get gauge data back to surface, that was a lot easier because they could then run those on anywhere between the four and the 24 watts. So power requirements by the subsea companies has gotten to the point where they've got these standards right there now, so trying to develop a system ideally all electric that runs off of 96 watts. So that's really the future goal.
And so you mentioned pressure and temperature as being the main measurements. What other measurements are useful down there and how do you use the pressure and temperature measurements?
So pressure and temperature, they can actually see what's going on between different zones. So having a tubing mounted pressure sensor and an annulus one, you can start to see where potentially cross flow might be happening and where one zone really isn't producing as much as you maybe thought. So sometimes it's worthwhile just shutting those zones in. So it gives them the control of seeing what's actually going on real time. So most of that pressure, temperature gauge data, they're using that to actually evaluate their reservoir as time goes on.
Okay. To get an idea of how well it's producing, kind of the health of the reservoir as time goes on.
All those things. So going forward, the more sensors that we can put down there and give the operator the information, the better. So the next ones that are coming out, you're talking about fluid density and detecting water. So if we can detect water easily, give them that information as well. So rather than having to go through, say there's five valves in the well, without going through shutting one, if we still got water, no, shut the next one, open that one, and going through that sequence, now you can actually do that straight away. You know which zone's producing the water. So you shut that one particular zone in.
Typically, in subsea systems, that can take quite a while if you're going to have to go through one valve after another and basically the process of elimination. That can take a while because you're talking about you talk to the subsea interface, tell it, right, close zone one. That whole operation may be a 30 minute operation. So if you've got to do that in a five zone system, you could see it potentially could take quite a while.
So having the real time monitoring and things like water detection is one of the things I think in the future is going to be a requirement.
Okay. Yeah, that makes a lot of sense. Now, one of the challenges we face is reliability and ruggedness of the electronics and survival at high temperature. We don't have the lifetime requirements you have. So I'm curious what kind of testing goes into testing even the mechanical systems, the polymers and the materials you use and the electronics and simulating that multi-decade lifespan.
Yeah, that's where it gets really quite complex. So a few years ago, a group called AWIS was started. It's a company in the UK that directs the group and what they're working on. So there was AWIS and there was also a standard, IWIS. So it's the standard for subsea interfacing and AWIS was a group that came out with specifics when you're going to test downhole equipment, how are you going to test it if it's going to have a five, 10, 20 year lifetime? So the specific testings that's called out in both those groups have specific testing detailed towards downhole safety valves, downhole packers, intelligent well valves, downhole gauge systems and gauges. So there's a lot of specifics that were put in there by operators and the various service companies right there. So this was not just one operator saying, "Right, here's what I want." It was a collaboration of many of the large and small operators out there, and pretty much most of the service companies that are currently in the industry today.
Okay. And so what are some of these tests? What do they look like?
A lot of is highly accelerated life testing. So certain time periods operating at high temperatures or higher temperatures than they're actually expected to be in life. So when you go to the extended temperatures, so say we've got a tool that we want it to be operating 350 Fahrenheit. We'll do this highly accelerated life testing at temperatures in the close to the 400 Fahrenheit and potentially more. So that can give you a life statement for the electronics. And it's very similar on the mechanical side. There's certain cycle testings, unloadings with certain pressures. It's quite specific, whereas before the way it was done is a different service company would say, "Right, here's what we've done this testing. Is this acceptable?" So there was no standard. So one operator could request certain testing that may just not be achievable. But by going to these standards, AWIS and IWIS, there's actually no standards that we can actually operate to.
Okay. Yeah, it's certainly nice having a common standard for everybody to adhere to versus kind of a free for all out there.
Absolutely. And the good thing of what that's done is that's actually improved the reliability of all the systems that were there. So the earlier days, reliabilities, if the reliability of the things were in the 80%, that was thought to be not too bad, but as we got into the early 2000s, mid 2000s, the reliability started to show up as being much higher as there was more data from more gauge systems being installed, more hydraulic and electrohydraulic valves being installed. Those reliabilities started heading up.
So I think that the number that most would quote for a downhole gauge system is somewhere in the range of 95% to 98% reliable over a five-year period. And hydraulic systems, so the downhole hydraulic valves, that number is up in the same range as well or thought to be. The big problem with reliability numbers like that is you don't get to hear about everything when it fails. So it's only when you get feedback from an operator that yeah, your gauge system's gone down, you put that into the numbers and that gets you at real time. So we try and ensure that we get as much reliable data from the operator in terms of the operability of their current system that they have in the ground.
Yeah. Now obviously, the market's in a very different place now than it was a year ago with oil prices and the whole global economy. Has that affected completions? And how do you see that playing out in the near term?
Yeah, this change and what's going on right now has seriously affected the completion sites from many areas. So a lot of the operators right now at the... Well, not so much just right now, but early on when this pandemic hit us, the price of oil dropped to zero. So prices anywhere even close to $30 a barrel, it's not really cost effective to run intelligent type completions and even just some more simple completions, it's not cost-effective to put those in the ground. It would end up costing them a negative amount. So they would end up... Awhile it might've been $20 million, it is now going to cost them $40 million. So it's not cost-effective in the current climate. We're very close to the number where a lot of systems now start to become a little more cost-effective.
I think some of the numbers I've heard going around is that if we're in the $45 a barrel range, some of these intelligent well systems, intelligent completion systems are now starting to become profitable for the operators if they installed them. All that relies on a successful installation and the quality of the equipment you put in the ground. Yeah, it's been too low for too long. We normally expect it to jump back up a bit there. The number I'd be comfortable with is if it sits at about $60, $65 a barrel and just stays there for...
Another decade, two decades.
That would certainly be fine. It's when we get the big spikes is where operators start putting more and more systems in the ground. But as soon as you get that little drop, now things start getting shot back. Wells get shut down. And the service companies, it's very difficult for a service company to cope with those big swings of up and down. So that's why working for service companies, you quite often find that every three to five years, this happens again and there's more layoffs. As soon as the oil price jumps back up to the $70, $80 a barrel, they start hiring. So over my lifetime, I've seen... I think this'll be four or five of these swings and drops in the oil price that have actually caused a lot of people to lose their jobs.
Yeah, it's a pretty brutal industry in terms of the cyclical nature. That's all the time we have for today. Thank you again, John, for joining us.
Yup, thank you. Thank you very much for having me.
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