Jamie Beard interviewed John Clegg for The Heat Beat in December 2020. This is a reproduction of her interview.
There are some missing pieces in the race to drill for and produce geothermal energy anywhere in the world. Some of these missing pieces are relatively low hanging fruit for the oil and gas industry with some attention and effort, like predicting optimal locations for geothermal development. Others are difficult and substantially more complex, including the ability to economically drill for deep hot resources. We must push the capabilities of cutting-edge oil and gas drilling technologies if we want the suite of “geothermal anywhere” concepts to take off and scale. Most (if not all) scalable geothermal concepts would benefit from the ability to drill directionally, and some are wholly dependent on development of that capability. In the case of closed loop systems in particular, which will require higher temperatures than EGS based concepts to be economically viable, this may ultimately require doubling the current operating temperature of existing directional tools. Most seasoned directional drilling experts agree that this is no small task and presents an array of technology challenges for which there is no solution currently. To quote perhaps the most pointed comment I’ve received from oil and gas friends about the prospect of developing a full suite of 300C+ directional drilling tools for geothermal: “That’s hard shit.”
But there is hope. I talked with John Clegg, a 30-year veteran of the oil and gas industry and directional drilling pioneer who developed one of the world’s first rotary steerables early in his career, and later worked on the world’s highest temperature LWD at Weatherford. Weatherford’s LWD was one of the tools used to drill the ultra-high temperature IDDP wells in Iceland, a toe dip into the semi-sci-fi world of magma drilling. And in a major score for the future of extreme environment directional drilling, John has started digging into geothermal. Our discussion has been edited for length and clarity.
JB: Tell me about your career in the oil and gas industry.
JC: I’ve been in the industry for over 30 years now, spending almost all of that time working with downhole drilling equipment. Of those 30+ years, I’ve spent about two thirds of my time in engineering and one third in sales and operations, but throughout my career I’ve been translating customer needs into deliverable products and services. As a result, I’ve always had a close eye on what customer needs are likely to be in the future and where the market is going. I’ve run numerous engineering groups, perhaps most notably the Camco team that developed one of the first rotary steerable systems in the world, the system that became Schlumberger’s PowerDrive. More recently, with Weatherford, I was responsible for the teams that developed their Magnus low-cost rotary steerable system and their HEX high-temperature LWD suite. I left Weatherford in June of this year, and since then I’ve been running my own consulting business as a subject matter expert in drilling and as an expert on strategy and innovation. Most recently, I started thinking about geothermal, and what directional drilling experts in the oil and gas industry can contribute to unlocking new capabilities in that space.
JB: Welcome to the green drilling revolution. What catches your attention about geothermal as an oil and gas industry veteran?
JC: I have to make a confession here. Until fairly recently I thought that geothermal drilling was all about drilling hot, wet rocks in places close to the edges of tectonic plates where there was volcanic activity. In other words, a very niche market. Then I began to look more closely. What I saw enthralled me. At scale, it appears that geothermal has the capability to work in sedimentary rocks in virtually every country of the world, and has the potential to allow every country to have a high degree of energy independence. If we can overcome the challenges, it looks as though we have the opportunity to provide effectively unlimited energy to the world with minimal environmental footprint. That is extraordinarily exciting and addresses so many global challenges.
But then I looked more closely through the lens of my experience as an oil and gas industry veteran. In order to realise the potential of geothermal, we’re going to need a large number of directional wells to be drilled. These could be complex directional wells. They could be multilaterals. They could resemble factory drilling. And, of course, they will require the ability to mobilise and deploy drilling technology all over the world. These are all things that we do every day of the week in our industry. It’s nothing that we don’t already know how to do. It’s a big opportunity for the oil and gas industry to reinvent itself, while retaining the skills and technologies that we have built over the last century. Importantly also, it isn’t a moonshot. This is an opportunity that we could start engaging in right now.
JB: You spent your career as a subject matter expert in directional drilling. What are the pain points in high temperature performance for directional tools currently?
JC: There are a few areas to be concerned about. Firstly, a lot of existing directional drilling tools use elastomers and leverage their compliance to provide sealing capability. Downhole motors use an elastomeric stator profile in their power sections, and mechanical devices like rotary steerable systems and MWD pulsers often use sliding or rotating elastomeric seals. It’s going to be hard to make dynamic elastomer seals work at high temperatures. It’s worth saying here that I’m less concerned about static seals like those used in the pressure vessels that contain downhole electronics. I think there are materials available to take static seals well over 300C. Those downhole sensors and electronics themselves, though, are more of an issue. For example, I don’t think we will get conventionally packaged electronics to work at or above 200C.
Other issues that we shouldn’t forget about are winding resistance and the elevated temperature capability of electrical generators and motors that many MWD and rotary steerable tools use. And, of course, you really don’t want to be using lithium batteries downhole at very high temperature.
JB: What can we do to push those limits in short order?
JC: For a start, there’s no need to use elastomers for dynamic sealing. We have already proved the capability of metal-to-metal sliding and rotating seals, even in dirty fluids laden with solids like drilling mud. It will require relatively minor design changes to get metal seals to work at higher temperatures. Electric motors and generators can work at higher temperatures provided care is taken over specification and manufacture of windings, for example. I think we will be able to replace batteries with downhole power generation.
People are testing metal power sections for drilling motors, and while there are challenges there, including sizing of gaps and management of solids, I think they can be resolved. That just leaves sensors and electronics.
JB: Right. Sensors and electronics at 300C and 20,000 psi. How do we get there?
JC: Well, pressure isn’t a big issue. We already have equipment rated to 30,000 psi static pressure, and while material properties degrade somewhat at higher temperatures, I don’t believe this is a showstopper. We also have diameter on our side. Most downhole electronics enclosures are designed for drilling holes as small as 6 inches in diameter. Geothermal wells will require a larger hole size in order to maximise flow rates. A larger hole size gives us a bit more space to increase cross-sections and overcome any temperature effects on material properties. Sensors and electronics are more of a challenge, but NASA has just demonstrated operation of silicon carbide integrated circuits at 480C, in preparation for a Venus rover. Maybe getting to that temperature really is “rocket science”, but it can certainly inspire us in our quest to get to 300C!
You could imagine an approach whereby we push existing sensor and electronics technologies close to 200C, and then use a combination of insulation and refrigeration downhole to get a higher temperature operational capability. As we are implementing the insulation and refrigeration, we continue to push the operational envelope of our electronics further, quite possibly using different packaging technologies, so that with our refrigeration capabilities we can operate even hotter. Gradually and incrementally, we get to higher and higher temperatures. Because we are drilling larger holes with larger tools, that additional space I mentioned earlier lends itself to adding insulation and refrigeration. Active cooling is going to require us to do some work on high temperature downhole generation, but again I think we can get there. Of course, we also have the ability to cool our electronics package by circulating drilling mud past it, and those higher flow rates will help here. So maybe rigs with big pumping capability, and maybe even continuous flow capability, will be part of the solution – at least in the short term.
JB: So back up for a second – why are we aiming for 300C and 20,000 psi?
Well, for me, sedimentary basins are of particular interest. If you look at estimated temperature at depth in sedimentary basins around the world (where this data is available – we need to do some work here as well on resource characterization), it seems that about 10km is really the maximum depth we’d need to go to reach economically viable temperatures for geothermal energy production anywhere in the world. 20,000 psi is a rough estimate of conditions at that target maximum, but in many places, adequate temperatures can be found at half that depth. As for temperature, of course the hotter the temperature, the better the project economics, but there is a reality that we will run into in terms of pushing the envelope on tool performance in high temperatures. In my mind, 300C is really the upper limit of what we can achieve without having to develop entirely new capabilities and make significant investments.
JB: How about high shock and vibe?
JC: This is an issue we have lived with for decades in oil and gas. Many of the solutions we have developed will be directly applicable to geothermal. A lot of concerns about shock and vibration in geothermal arise from drilling igneous rock, but sedimentary rocks are much easier to drill. Of course, geothermal wells will be deep and the length of the drillstring, and its lack of torsional stiffness, will certainly set up the potential for vibrations – but we have drilled oil wells more than 12km deep, much deeper than many economic geothermal resources, so again we can lean on past industry experience. We also have the opportunity to change the contracting arrangements for drilling geothermal wells. This last point may seem irrelevant at first when considering the question, but a big concern of mine is that drilling practices and wellbore quality are often sacrificed on the altar of drilling wells as quickly and cheaply as possible in order to meet contractual targets and incentives. Drilling a little more carefully would eliminate many of the worst shock and vibration-related problems we currently see and ensure better wellbore quality. This would make it a lot easier to compete the well once it has been drilled – making it smoother and less tortuous, and easier to run completion strings into. We as an industry need to back up a bit and take a look at how we can integrate better to tackle the particular challenges we will face in geothermal.
JB: Do you see oil and gas engaging in this space in a big way in the coming years?
JC: I dare say yes. It presents a huge opportunity for the oil and gas industry, and conversely the industry can help to accelerate the development of this truly green resource, so it’s a win-win as far as I can see. With some modification as described earlier, oil and gas can bring critical technologies to allow complex wells to be drilled: MWD and telemetry to measure the well location, rotary steerable tools to maximise wellbore quality and ensure well positioning, and automation of rigs and rotary steerables to optimise the drilling process – true factory drilling!
JB: What are your plans now that you have taken a walk on the green side?
JC: I’m working with SPE and with the UK’s Institution of Mechanical Engineers (IMechE) on how the skills and experience in oil and gas can pivot to alternative energy – including geothermal, and also hydrogen. It looks as though these two can be very complementary of one another, so that’s potentially another win-win. And, specifically, I’m doing a deep dive on how current MWD and directional drilling technology can be deployed in high temperature wells.
JB: Is there a geothermal startup in your future?
JC: That would be fun!
The post above was originally published on heatbeat.energy on 4 December 2020. In less than a year, we have come a long way! Since this interview was posted and John was asked about a start-up possibility, we have launched Hephae Energy Technology to create MWD and directional drilling technology for higher temperature wells than can be drilled with conventional oil and gas equipment. And we have learnt more about adjacent technologies – as a result changing our view a little about how we will enable high temperature drilling – and become even more confident in our conviction that we can do it! The Hephae team has participated in numerous panel sessions including at PIVOT2021, in a Shark Tank event for SPE Gulf Coast Section, and was a finalist in the Pivot2021 new venture competition, pitching to Chris Anderson and Richard Branson. The team is currently looking for seed funding to start development of its high temperature drilling system.