In this comprehensive follow up on the PIVOT2020 virtual event, Dave Waters shares his take on the transition from oil and gas to geothermal, technical and industry differences, challenges, technology opportunities and more.
In a rather comprehensive follow up on the recent PIVOT2020 virtual event, Dave Waters, Director & Geoscience Consultant at UK based Paetoro Consulting UK Ltd. shared his take on the event and specifically the panel he was involved in.
With the wealth of his commentary and extent, it is difficult to share as a whole, but here it is published with his permission.
Recently I was happy to take part in the IGA/GEO/University of Texas arranged PIVOT 2020 discussion as a panellist – perhaps representing those of us stepping into geothermal relatively recently from a career in oil and gas. For me the process first started in 2016, and it has been a very enjoyable and eye-opening learning curve. The brief we had as a panel was “Geothermal Prospecting: Thermal and Hydrothermal Exploration”.
The discussion was fun but we only touched on a fraction of the things we’d briefed ourselves for, and there were a lot of interesting questions from the audience we were unable to address at the time. The discussions are still available following the link below and clicking on the relevant day (16 July).
Having read through the audience questions provided by our moderator Philip Ball, there are some general themes coming through, and so I will talk to them here. It’s a bit long winded, apologies, but please use the contents list given below to skim and skip to items of most interest. As a lot of questions were similar or relevant to over-riding themes, rather than address them individually, I have responded thematically. In case it is not blatantly obvious, the views are expressed are just mine, and not necessarily those of anyone else on the panel or any of the organisations involved in PIVOT 2020.
Preface: geothermal is grown up already; The biggest fundamental differences with oil and gas; Some key similarities with oil and gas; Love it or loathe it, it’s all about the money; Defining some key types of geothermal, and defining geothermal reservoirs; Types of permeability & exploration methods – seismic and non-seismic, exploring for fractures; Heat and permeability destruction, scale and chemical equilibrium issues; New versus existing technologies – do we have to try that hard just yet?; Technological insurance of new options; Plays and spatial variability, and the modelling game; Thinking heat plays; Geothermal anywhere – the premises and the problems – a balance of enthusiasm and expectation management; Database dilemmas; Reservoir thermal energy storage and hybrid renewable projects; Geographical potential and the element of scale; What has been hardest in transitioning to geothermal (so far)?; One for you?
Preface: Geothermal is all grown up already…
Firstly, a word. There is a danger that we in the O&G industry think we can magically swan in and solve all of geothermal’s longstanding problems, with our flashes of brilliance. The truth is that many brilliant professionals and specialists in the field have been working geothermal for decades upon decades, and that crossovers and cross-fertilisations between various subsurface industries have been going on for generations already. There is not much in the oil and gas world, that somebody hasn’t tested along the way in a geothermal context.
There are of course ways of doing things that are continually evolving in each, and yes, there is perhaps scope for more sharing of workflows – but the old adage “nothing new under the sun” is often true also. If it were that easy to make a big difference quickly it would have been done a long time ago. That said, sometimes incremental improvements in enough workflows can together reach a critical mass to genuinely change things, so it is important to keep checking. If we are new to the field though, we should recognise that there may be very real reasons (and not just technical ones) why things we think should apply haven’t been more widely applied, and sometimes it takes a while to realise those. Tread carefully. Read and talk widely before coming to premature conclusions. Listen to the geothermal community.
It is no good reinventing wheels if the only thing working to date is caterpillar tracks. Before we hop into our re-purposed geothermal Audis, it might pay to note if all the geothermal community are driving tractors. They might know something about the road conditions ahead that we don’t yet.
The biggest fundamental differences with oil and gas
- The commodity – fundamentally heat – cannot be stored for long time periods without conversion to some other form of energy. It degrades on short time scales in a way hydrocarbons don’t. Since steam or hot water loses its heat quickly, the use or conversion to power of the commodity has to be close to where it is extracted from the subsurface – if it wants to be commercially viable. Market has to be close. That is more so for heating than if you can access a power grid and/or associated energy storage facility, but nevertheless, close.
- Geothermal energy has competitors who can offer exactly the same commodity without the capital expenditure of drilling or the geological risk. That is an absolutely critical thing to remember. Wind turbines and solar do not need to spend millions first before they even know if even they have a resource that might work. The sun is there for everyone to see. The wind is there for everyone to feel. The rock temperature and permeability 3 km below is not. There has to be something else of value that makes up for that cost and risk. It has to come in the form of longevity and amount of energy supply, benefits that typically only emerge when averaged over longer time periods. That takes a special kind of investment partnership.
- While biofuels are increasingly introducing an aspect of similar surface based competition to hydrocarbons, their share of the market is currently tiny and for all practical purposes anyone who wants to sell hydrocarbons on a global market is up against competitors who are also facing the same geological risks and drilling costs. The competitive playing field is much leveller for oil and gas than it is for geothermal.
- Unless for direct application at an offshore rig or platform, geothermal energy is focused onshore. That means greater proximity to people, greater environmental, regulatory and social concerns. That’s less of a problem if you are onshore in the middle of nowhere, but then market and commodity infrastructure/transport become a problem that is not nearly as severe for hydrocarbons.
- This means that if anything goes wrong – induced seismicity, subsidence, contamination, you are going to have a whole lot bigger headache on your hands, and a much more critical audience, standing with placards at your gate, than you could ever imagine happening offshore. In some places for historical and social reasons fracking and EGS stimulation will not be possible. It is that simple.
- It also means seismic is not going to help us as much as land seismic is harder. Noise, statics, substrates etc, make things harder, not to mention the practical acquisition difficulties of taking a seismic survey down the main streets of a town or city where the market is. As a consequence non-seismic exploration methods often figure much more highly in geothermal exploration workflows.
- While subsurface permeability and volume are typically subsurface objectives just like oil and gas, sometimes in geothermal the permeability can be natural fracture hosted, which is altogether harder to resolve and predict.
- The profit margins are simply far less for hot water and power than they are for oil and gas. While portfolio approaches can always help spread risk and cost, in hydrocarbons it takes far fewer successes to cover the costs of failures than in geothermal. When up against typical commercial success rates, that matters. Covering all the costs of exploration failures in the early stages of exploration from successes may not be possible in the way that it is in oil and gas, and strategic incentives from public or private investors are typically needed to help cover the initial exploration phases.
- Infrastructure. The margins in oil and gas mean that if you make a decent find you can happily think about a pipeline to your local refinery. Not always, granted, but pipeline costs are not so often the main bust. In geothermal, the costs of new power grid, or new district heating infrastructure, are often a bust on practical application even when all the geotechnical elements are coming together happily. The margins involved in success for any geothermal exploration are not typically up to the job of also funding big infrastructure projects, and so for the costs of those to be loaded on initial exploration projects often kills them. Where there has been success, it has often involved a decision by governments to spread that cost over time, with early exploration incentives to get things to the more profitable widespread production phase. That might include funding long lasting infrastructure (and employment generators) like district heating networks.
- The part of the reservoir targeted might not be the same as for oil and gas. Geothermal is not targeting for a commodity that has a very strong buoyancy drive to reach for the top of the reservoir, as with oil and gas. In geothermal, heat and temperature is not the only thing of importance – delivered volume of hot water/steam is just as important, but it is worth noting that all else being equal, the best temperatures will tend to be deeper, not shallower.
- The customers are different. Especially for heat. Horticulture, local councils, hospitals, universities, civic centres. These are not organisations that are easily comfortable with up front capital spend of millions for something that is unproven until the money is largely spent. That has to be managed imaginatively and courted delicately.
- In geothermal, we are also of course interested in the thermal parameters of the rocks and the way they affect the flow of heat, not just water. The thermal conductivity, diffusivity, and the heat flow, and how these vary vertically and areally.
- On the plus side, once the drilling has been done and we are down in the reservoir – if things are working, and the resource is managed appropriately, we will not exhaust the resource in the same way that oil and gas physically takes the commodity out of the ground never to return. Temperature and pressure declines can happen without careful management, but geothermal can keep trundling on happily for decades in a way that oil and gas can only dream of. Locations for infill drilling will not be your biggest headache.
- Another caveat is that some geothermal technologies are increasingly investigating the closed-loop conduction scenario. In such situations all we want from the rock is its conductive heat and not its permeability, and so the risk on permeability is totally bypassed and exploration methods therefore adjust to being thermal parameter focused. There is a trade-off in that the volume of hot fluid and the volume of rock available to supply heat is also reduced to that which you can contain and pump through the borehole(s), so that can impact commerciality. That might not be a problem if your rocks are hot enough, but that also of course implies deeper and costlier drilling – so more trade-off. These are developing subjects whose tests are ongoing.
- There can be important differences in well design, often due to the amount of plumbing (such as tubulars and pumps) that have to go down the hole and the size of the hole required to accommodate the kit needed. In conventional geothermal there will often (not always) be a need for two wells also – i.e. a producer injector doublet to sustain pressures. This might not always be needed in recovery of a more buoyant pressurised fluid such as oil or gas.
Some key similarities with oil and gas
Both conventional geothermal and oil and gas look typically for subsurface volume and permeability. Any process used in either to help with that – can have uses in both. It’s that simple. A caveat as mentioned already, is that the permeability being sought in geothermal is more commonly not in sedimentary rocks than is the case for oil and gas. It is also typically onshore and much nearer to people. That impacts a lot of exploration methods. That said, a huge amount of geothermal potential exists globally in sedimentary rocks just like oil and gas.
Drilling efficiencies are also of course something that helps both – though completion designs are often somewhat different due to the kit that has to go down the hole, amongst other things.
Personally, I suspect the biggest contribution oil and gas can make to geothermal is not on the technical side – though of course there are offerings. It is in its long ability to deal at scale with raising finance when faced with geological risk. This is a concept that oil and gas is very familiar with and it has long relationships to investors who know that. Being brutally up front about it, the best thing oil and gas can bring to geothermal is its wallet and its financier friends.
Love it or loathe it, it’s all about the money
Realistically though, is there any interest on the part of O&G investors to come to the geothermal party? The honest truth is that (so far anyway) it has been much harder to make large amounts of money on shorter term time scales (<5 years) in geothermal than it has been historically for oil and gas. The money, when it comes (it does), takes longer time scales. Investors can reasonably ask – why bust a gut on hard long smaller stuff when short easy big stuff is available? Harsh but fair. The thing that is changing now, and why many more may consider coming to the geothermal party – is that appetite for green energy is across the board increasing. The costs of not caretaking the planet responsibly are hitting home. There are billions and billions available in this finance space right now. Almost everybody gets the need. Being convinced of the best “how” is much rarer.
The costs of emitting CO2 into the atmosphere, even if not formally enshrined in carbon taxes and the like, are becoming increasingly apparent to investors and the public. Make no mistake the former care what the latter think – because ultimately the public is usually the customer. Governments have environmental legal obligations to meet in light of climate change, so they are interested too. The appetite for longer term investment is increasing. It is not universal and some investors will never be interested in geological risk when there are fizzy drinks or insurance policies to sell, but that’s OK. We don’t need everyone to like it.
Risk? Well actually it is remarkable how up for risk many investors are. They get it. They are not afraid of it. What they do like to see though is scale of reward. Why invest all that time and effort if at the end of the day there are only seventeen places it can be applied globally. That is an image problem geothermal faces to some degree. Make a case that it can be applied in 17000 places and not just 17, and there will be a whole lot of ears a whole lot more ready to listen.
That case though, must be made quantitatively and in detail. The onus is on technical professionals to communicate that. Money will not fall into our hands at the mention of some concept. A large part of my efforts in geothermal are aimed at providing the technical and commercial bridges that turn individual geothermal projects into at-scale multi-project scale propositions.
Having said that it is all about the money, I think it is also important sometimes at the feasibility stage, to not get to hung up on what is economic now. Investigating conceptual case studies and analogues as a kind of geothermal “play money” to see whether a project flies commercially or not, before the real money is spent, is a useful thing to do. And if there are commercial busts, knowing what they are and how big they are begins the conversation on whether anything can change in the future to help with that. That assist may be technical, commercial, or regulatory, or simply economies of scale and repeatability. Whatever it is, that process of quantitative investigation helps inform the next steps, or just as important for any investor, the speed of exit.
Defining some key types of geothermal, and defining geothermal reservoirs
To the purists amongst us, geothermal energy is that energy derived solely from the primordial heat of the Earth’s formation and all those impacts that took place at the formation of the solar system, plus the ongoing contribution of radioactive minerals in the crust and mantle (potassium, uranium, thorium). These contributions exist in roughly half and half proportions to the earth’s surface heat flow. Discussion of ground sourced heat pumps (and water sourced too) is sometimes included in discussions of geothermal energy – these being bits of plumbing that exploit temperature differences in the ground and water of the near surface with our air, due to daily and seasonal changes arising from the solar radiation that reaches Earth. In that sense this, sensu-stricto is not pure geothermal energy but more akin to a form of solar energy, where our crude solar panels are surface ground and water. These daily and seasonal variations typically don’t extent much below 20 m depth in the ground. Personally, I have no very strong opinion, as long as discussions and figures make it very clear what is being discussed. Delving into the published statistics on geothermal energy, that is more often a problem than you might think.
Shallow and deep geothermal likewise has a variety of different definitions. Some will include ground sourced heat pumps in shallow geothermal discussions, other purists will regard shallow geothermal as only that element derived from the Earth’s heat, and not the sun’s. Around the world, formal definition of shallow geothermal is sometimes made, and usually these mention lower depth thresholds in the range 300-500 m. If you are a geothermal purist, you can also add an upper bound to it around 20 m to distinguish from the ground sourced heat pump element, or if not, you might not care so much. Whatever the case, say which. Deep geothermal therefore falls into the anything more than 300-500 m category. All else being equal, heat and pressure destroy permeability and porosity with depth, and of course drilling costs increase with depth, so this makes deep geothermal a significantly costlier and riskier game than shallow geothermal. Drilling costs are not linear with depth. The deeper it is the more per metre depth of drilling you will pay.
Another key distinction is between low and high enthalpy geothermal. As far as I can make out, the boundary has arisen from the threshold above which it is easier to extract power (steam for turbines) using conventional geothermal. With the caveat that pressure is important too in a context of driving turbines, this temperature threshold is around 150-180 deg C. Enthalpy is a term that incorporates not just temperature, but the total internal energy of a fluid and its pressure and volume, so it is a better thing to evaluate that “punch” a fluid has to drive a turbine. If we sometimes hear the terms high and low temperature geothermal, they are typically also a distinction around that temperature threshold. Down to temperatures of 75 to 80 deg C note that it is still possible to make electricity from geothermal, but it involves “binary” systems with the use of a second (organic) fluid that has a lower boiling point than water to drive the turbines.
Whether we are intending to provide power or heat for the customer is therefore a critical consideration in exploration risking, and so another way of differentiating geothermal. If heat rather than power is the main consideration, then strangely temperature is in some ways less of a concern. Heat pumps can always condense heat from lower temperatures to higher ones as long as there is a plentiful volume of hot water – albeit at a cost of efficiency and energy to drive them, and volume of end product. Heat after all is a function of mass and specific heat capacity, as well as temperature. When civic centres in Glasgow can draw heat from the Clyde River, a sense of what is possible becomes apparent.
So, increasing mass (i.e. volume and flow rate) can increase heat supply too. That said, heat pump efficiency is a function of the temperature coming in, and to what it can be cooled to, so the hotter the better, but lower temperatures need not be the end of the world. If the objective is to supply a customer with the heat to grow cabbages in greenhouses, then we don’t need 190 deg C. In that sense, there is no real lower bound on temperatures that can be used, just a sense that the lower the temperature the more restricted the uses are for which commercial returns can be generated. If however our game is to generate power – which has all sorts of benefits in that infrastructure is much more widely available, then temperature constraints do become more of a limitation.
Bear in mind that capability of heat pumps also poses important questions for the competitiveness of deep geothermal. If they can do such clever stuff at the surface, why dig deep? Digging is never a cheap activity. The detail of volume and temperature and commodity price makes the difference as to which is most competitive. Deep geothermal can at the end of the day – in the success case – deliver much bigger volumes of much hotter fluid, and those efficiencies can translate into greater competitiveness. Such outcomes though need somebody to sit down and do the math and no play map is ever going to tell you all of that story.
Another big category division is between closed systems and open systems. Open systems are much like conventional hydrocarbon exploitation in that they are reliant on use of the fluids within a reservoir to extract the commodity – in our case heat. These well bores interact with the fluids of the reservoir and commonly include injector producer doublets, to maximise the catchment of heat flow that is being accessed and sustain pressures. Single well bores are possible too but pressure maintenance becomes more of an issue and the volume of rock from which heat is being extracted will be much smaller. That potentially impacts profit margins.
Closed systems in contrast are completely isolated from the fluids of the reservoir and rely on the rocks at depth solely for their heat contribution. As such they are less interested in rock permeability than they are in its thermal parameters (though host rock permeability might influence heat flows within a reservoir, especially if deep seated fault zones are involved). They are concerned with how efficiently the heat can be conducted from the surrounding rock into the fluids of the well-bore. In conventional open systems we are usually restricted in the subsurface to the use of water in the reservoir (i.e. hydrothermal) although other options such as CO2 are being evaluated too. Any use of organic fluids though is restricted to surface (ORC) facilities. In closed loop systems however, the option is there to use other fluids instead of water as the vehicle for heat extraction – these are referred to as phase change materials or PCM’s.
Other types of geothermal distinction fall around the geothermal play type being sought.
However, we are now in a place to think about what a geothermal reservoir is. Our commodity of interest is heat, so in essence a geothermal reservoir is something that stores heat for us to extract in some way. The message behind the “geothermal anywhere” mantra stems largely from the fact that any rock essentially does that to some degree, so geothermal reservoirs in this loose sense are indeed everywhere.
The devil is in the detail of how efficiently and how cheaply we can extract that heat from them, which of course depends on the various techniques we deploy to do so and the rock character. Sometimes we exploit permeability and water to extract that heat from the geothermal reservoir (i.e. conventional hydrothermal), in which case those parameters will be implicit in a geothermal reservoir’s definition. In others, as discussed, we don’t, and it won’t.
There, in “thermal exploration” the heat flow, thermal conductivity, and thermal diffusivity will be key parameters. Thermal conductivity for heat is a bit like how fast a relay runner can run – how quickly it steals the heat and runs with it. Thermal diffusivity is about how good it is at passing the heat “baton” on – how sticky it is at holding the heat until it gives it away. Heat flow is about how much energy the sprinter has to run in the first place. Has he or she had enough Weetabix for breakfast to run competitively…
Types of permeability & exploration methods – seismic and non-seismic, exploring for fractures
Critical to the exploration methods we apply is the type of permeability we are seeking. If we are chasing lower enthalpy geothermal (typically less than 150 deg C) for hot water direct uses or organic-Rankine-cycle (ORC) binary-fluid power generation, then the sedimentary basins onshore that are frequently chased for hydrocarbon resource are fair targets. Consequently, many of the exploration methods are the same. Except when onshore locations or locations near to built-up areas limit the options. Beautiful offshore marine seismic of the kind that is available today is not going to be much help to you in geothermal exploration. Land seismic is improving significantly with time as noise processing algorithms improve (I’ve seen some amazing onshore sections in my time), but they will most likely always be in a different league to marine seismic. There is just so much more near source variability to disrupt the signal.
Hot dry rock systems of the kind chased in crystalline rocks are very different and might not lend themselves nearly as well to seismic. There the permeability can take various shapes and forms – cooling joints, tectonic fractures, weathering zone poroperm, even karst (as per Lancaster field) – and hydrocarbon exploration in fractured basement reservoirs is helping a lot here. Many of the learnings are directly transferable, the caveat being again, that seismic resolution of sub-vertical fracture systems is tricky at the best of times offshore, so taking that onshore is even harder. That said, large fault influenced fracture corridors are frequently detectable, and inversion techniques for detecting fracture porosities and permeabilities are also increasing all the time. It should be readily apparent though to any subsurface geoscientist, that the porosities and permeabilities inherent in sediments are – for all their complexity – easier to make generalisations about than the permeability of naturally occurring fractures.
That may be derisked somewhat if we can employ EGS techniques (enhanced geothermal system) to engineer an increase in-situ permeability – by pumping up pressures to induce minor shear failure. Due to induced seismicity concerns this will be more acceptable in some communities than others, and it is likely there are some places where it will simply not be an option, however carefully it is planned and monitored. The other way of derisking of course is to adopt a closed loop approach – where the only permeability you have to worry about is that of the well bore itself, but then you have to feel happy that the compromise on the volume of fluid and heat you can access leaves the project still viable.
Whether we are dealing with exploration in hard crystalline rocks or basin sediments has a strong bearing on the exploration techniques available to us, but in all rocks gravity and magnetic gradiometry, magnetotelluric, and resistivity techniques such as electrical resistivity tomography are continually making new headway. These however are often sensitive to depth penetration and the contrasts in density, resistivity, and magnetic character that are present in the rocks. Whatever the contrast we are trying to detect in a rock, we have to have some fundamental sense that a meaningful contrast is there for a detection technique to be viable. Seismic wouldn’t work if there were no impedance contrasts. The name of the game is to also obtain a resolution and accuracy that is better than what we can do already from modelling techniques. There is no point in spending millions on some fancy black box if it doesn’t reduce the uncertainty that broad-based modelling from offset data can already achieve.
Many techniques rely on understanding the response of real rocks in the subsurface. That is why measurement, measurement, measurement, wherever we can wangle it is helpful. Predicting the rock is easier if we already have a known library of rock responses, for velocity, density, magnetism, resistivity, to compare with. The more local they are, specific to our basin or setting, the better. There is always a cost benefit exercise to be undertaken with data collection. Time on a rig is not cheap, but in an exploration phase, the value of real measurements on real rocks down-hole or retrieved for work in the lab later is difficult to overstate.
One interesting new development is the use of radar for subsurface penetration. this is something that has been known about for some time. The depth to which this can be achieved reliably is an evolving subject and not without an issue or two – but things like the ESA Mars Express MARSIS tool that is orbiting Mars and detecting sub-glacial lakes of water beneath the south Martian pole at depths of around 1 km, give a sense of what can be possible. Where dielectric contrasts facilitate it.
Again, there are important questions of uniqueness of response, accuracy, resolution and reliability, and familiarity with the key parameters of relevance in real rocks. Especially the contrasts – for example in the dielectric relative permittivity – that might exist in the rocks to assist detection. Electromagnetic methods like this are always operating in a noisy environment. Earth and the universe, are not electromagnetically quiet places. That means there are always limitations to what can be achieved, but they are an interesting option to explore further and down-hole dielectric logging tools are available from most big vendors to help with calibrations going forward. Calibration is key.
As with any subsurface exploration in the 21st century, the answer lies not in some magic tool that will tell all, but in an integrated arsenal of weapons to derisk, whose sum is far greater than the contribution of any single part. Lots of arrows in the quiver as we hunt. Increasingly, with caveats, there is also the opportunity to deploy these things in pursuit of multiple resource types – thermal, mineral, hydrocarbon, and subsurface storage – and to do so simultaneously without too much compromise of each.
Heat and permeability destruction, scale and chemical equilibrium issues
Heat and pressure – as an audience questioner pointed out – tend to destroy permeability, so if we need in-situ permeability this generally becomes more of a problem as we go deeper. In truth though, there is no shortage of sedimentary rock permeability at depth around the world. I’ve held core from German onshore Rotliegend reservoir from 5 km depth and felt it crumble almost like beach sand – in that case largely due to feldspar dissolution effects at that depth (if my memory serves me correctly – and just a tiny bit at the edges – I was careful honest…). So yes, deeper can be a problem, but occasionally diagenetic changes work for us too.
Even when they don’t, if sedimentary rocks have decent enough primary poroperm to start with, they can keep it to surprisingly large depths. I was told by a kindly geothermal professional at the start of my geothermal escapades that as a rough rule of thumb a 100 m thickness of 50 mD or more starts to become a going concern – as long as it extends over a decent area (e.g. around the producer injector doublets typically 1-2.5 km apart). That won’t be everywhere, and yes, it is a risk, but such poroperm conditions exist at depth in many places and we often have the hydrocarbon wells nearby to prove it.
It is always important to remember though that hot fluids in the earth contain solutes, and as the temperature of that fluid changes some of them will precipitate out. The handling of such chemical “scale” is a big aspect of any long-lived conventional, open-system geothermal operation. It’s not a showstopper, just something to be aware of. It is also important to recognise that the deeper and hotter we get with our reservoir fluids, the more corrosive and trickier those fluids are going to become, when handling with conventional metals. Supercritical applications being discussed operating at very high depths and temperatures will find this a particular challenge. This ain’t no elderflower cordial.
If fluids of any kind are being injected back into the reservoir to maintain pressure, we also have to think very carefully about the issue of temperature and geochemical equilibrium. Putting a cooler water down into a warmer reservoir might just precipitate things we don’t want and occlude permeability. Or as was the case in Germany, putting water down hole that is not in geochemical equilibrium with rocks could just dissolve some of them and/or hydrate some of them and cause ground movement – especially in a shallow geothermal situation – and especially if evaporites are a lithology in the equation. This question becomes even more pertinent if the fluids involved are not water – things like CO2. Then it is not just the chemical reactions that might be induced, but also the very different physical abilities to exploit in-situ permeability in the rock. The relative permeability of gases relative to liquids comes into play, as does the effect of slightly acidifying reservoir waters if carbonates are involved.
These risks all have evolving mitigating workflows that can be employed to help. Satellite based remote sensing is becoming very good at monitoring minute changes in surface elevation, and gravimag too can detect changes actively occurring in the subsurface. But it is a good point to note that as a rule of thumb, the shallower and the more conventional the reservoir (i.e. in a hydrocarbon sense), the lower the drilling and geotechnical risk.
New versus existing technologies – do we have to try that hard just yet?
Anyone reading the field of geothermal at the minute can’t fail to be impressed by the breadth and diversity of technology being employed to improve things. Closed loop conduction. Supercritical high T high P geothermal exploration. CO2 plume geothermal. Then we have existing tech applications not just for power generation, but for desalination, horticulture, ground protection, district heating, agriculture, aquaculture, etc etc. Combined efforts too with other renewables including district heating and reservoir thermal energy storage. All these things stir the imagination.
New technologies do always carry risk though, and evolving them to a point where they are routinely commercial can often take a long and difficult to predict path. The unforeseen is by definition unforeseeable. This new R&D should be pursued with enthusiasm because the potential gains are large, but as I stated in my own PIVOT 2020 participation, the thing that really excites me is the scale of resource that is already available using existing technologies and conventional geothermal, hydrothermal resources. So often the real bust is not in geotechnical aspects and risks but in telling the story, increasing awareness of resource scale, and in getting the regulatory environments and other protocols (including existing databases) aligned.
That is to say, getting all the bits of the jig-saw already sitting there on the table assembled to make the geothermal picture. The new technologies are a fantastic and exciting bonus very worthy of attention for the rewards they might deliver, but they are not a prerequisite for large scale deployment of an existing resource. Those conversations can begin en-masse already without having to wait for the maturation of these new technologies. To catalyse that though, an appreciation of the scale of resource potentially on offer has to be quantitatively communicated and that is where I see both a great challenge and a great opportunity – for those willing to put the wellies on and wade into the hard graft of technical and commercial data mining.
Technological insurance of new options
While existing technologies already provide significant opportunity, an area where new technologies may be able to help in the future is in providing additional technological insurance. Where conventional options might rely on certain temperatures and permeabilities, in the future some of these new technologies could provide additional assurance that some gain can be extracted for relatively little extra spend, even if the permeability or thickness encountered is not totally as expected. They give options for further cost recovering and profit delivering, plan B’s. This is something I know others are thinking about more. Historically EGS has provided a similar security blanket for permeability, but predicting its results remains geologically uncertain with risks of its own, and in terms of social licence may not be an option everywhere.
Plays and spatial variability, and the modelling game
There seems to be a bit of a misconception in oil and gas that play concepts have not been deployed in geothermal exploration. They very definitely have been and are. Many authors have employed a variety of techniques. The PIVOT 2020 audience mentioned a few examples. I think the differences with oil and gas are twofold – firstly oil and gas plays revolve around petroleum system elements of source, migration pathway, reservoir presence and quality, seal, and trap geometry. In conventional hydrothermal exploration within sedimentary units these can all be applied, except that we are no longer worried about source and migration, since the water we know to already be there. In that way finding a technical resource is in many ways less risky than oil and gas – very obviously we no longer have to find hydrocarbons – just a reservoir – and that is easier. Where it is riskier is making money out of what we have found.
That increased commercial risk is a very important thing to grasp with geothermal. It is no longer the case that where our technical common risk segments all come together beautifully assures a good chance of commercial success. With geothermal it can be optimal in this regard and still fail commercially if there is no viable market nearby for the heat found. The commodity is transient and needs to be close to market to be exploited, and there are many more competing alternatives for the same commodity.
So, play maps are a great and widely used tool in both oil and gas and geothermal (check out some of the Dutch TNO website applications, or Danish papers on the subject) but a big difference is that they get us much less further down a path to commerciality than they do in oil and gas. Where margins are lower, getting those commercial market sensitivities accounted for much earlier in the exploration process becomes much more important. That’s why heat demand maps and knowledge of where existing heat infrastructures and big potential customers are present, is important. Then a “commercial play” exercise can be overprinted on any geotechnical ones. This is something I’ve considered myself in a UK context. There are a few blogs here on linked-in illustrating the concept.
Thinking heat plays
One thing that is perhaps a little newer, though I’m sure others have thought this way already – is thinking not of permeability (& petroleum) driven play systems, but heat-system driven plays. Let’s think about that – source, migration pathway, reservoir, seal. These are all things related to flow, and we can translate them to heat as well. If we for a moment think (incorrectly) of heat flow as more or less equal into the base of the crust from the mantle lithosphere, then that is our source.
The heterogeneities in thermal conductivity within the rocks of the heterogeneous crust, steal that heat differentially and condense it into more complex pathways within the crust. They are our migration pathways in the “heat play” system. Things like salt, granite, and quartz rich lithologies, (sandstones, quartzites), but also to a lesser extent dolomite and other carbonates, are better at stealing the heat flow in this way. Shale, mud rocks, clays, and quartz poor rocks like basalts are not as good, and act more like thermal “seals”, i.e thermal insulators. Where lithologies, through natural processes like plutonic intrusives or evaporitic diapirs, also provide structures with a large vertical extent – then they are even more important from a migration perspective. They work to collect and bring the deep heat to a shallower geothermal reservoir. That may or may not be capped by a thermal “seal” like shales too. Our geothermal reservoir may or may not need permeability and water to extract that heat – depending on whether open systems or closed-loop conduction are being deployed.
The oil and gas industry is very good at logging and sampling and modelling porosity and permeability (importantly, in that order – logging, sampling, modelling), and merging this hard data with softer remote sensing data types like seismic. Stochastic modelling techniques to infer realistic models of porosity and permeability variation in paces where they are not known, help to avoid unrealistic expectations. The geothermal industry is at a stage where the larger regional “play” style maps are being recognised as inadequate for predicting the detailed observed variations in heat flow and thermal parameters, as well as the enduring struggle to know permeability. The time is ripe to take things to a new level of granularity for these thermal parameters.
There is perhaps room to think more in these “heat play” parameter terms and to model smaller scale variations in a similar way to poroperm. There are physical differences though. The thermal parameters are very dependent on the mineralogical and chemical composition of a rock, not just the solely physical character of porosity and permeability. Those variations might occur on much smaller and therefore more difficult to model wavelengths. For instance, variations in sandstone provenance might influence significant changes in thermal character for relatively similar porosity and permeability.
In any case, taking more measurements of the parameters of interest is the most important step forward. Modelling approaches often have a way, in the sophistication stakes, of getting several steps ahead of the data available to them. The most important thing the oil and gas and geothermal industry can do collectively going forward, as well as looking at imaginative financing options, is to collect more data routinely on the thermal and electromagnetic character of real rocks in addition to the poroperm and velocity information that tends to dominate.
In that sense, the PIVOT 2020 audience questioner who mentioned core programmes has grasped the right end of the spade. A fundamental of exploiting the heat of real rocks, is, unsurprisingly, to make lots of measurements of the parameters that dictate the heat of real rocks. We can make theoretical assumptions and wave our arms about over regional map interpolations and models all we like. That has its place, but resolution of the kind we need will ultimately come from real rocks.
Geothermal anywhere – the premises and the problems – a balance of enthusiasm and expectation management
Whether closed loop conduction systems can work on a large-scale commercial basis is still a hypothesis being tested but it’s worth noting a lot of knowledgeable people are getting quite excited. The concept relies on the hot rock and a fluid in a closed-loop well bore conducting heat from rocks outside it. They remove any reliance on in-situ rock permeability and instead rely on a rock assemblage of certain thermal character under the influence of a certain a heat flow. They are pretty much theoretically possible everywhere. That is the gist of “geothermal anywhere” and its sit up and notice “what?” moment. If you are a Disney movie fan, it’s a little bit in the same vein as Ratatouille’s “anyone can cook”. You can always find hot rocks at depth if you go down deep enough. However, there are immediate hot-fluid-volume constraints associated with such approaches, on top of non-linearly increasing drilling costs the deeper (or longer) you go.
The challenge is therefore to do so cost effectively and competitively against all the competing alternatives that may exist at the surface. So, while there is cause for enthusiasm in that these technologies bring the prospect of geothermal into places it might never have been considered before, there is also a case for expectation management. Something being technically feasible is not an assurance that it can be commercially competitive. That said, there are projects under way even as we speak, testing such feasibility. Reasons to be cheerful.
When initiating down new routes it is good and necessary to be enthusiastic, but it is also important not to unwittingly or otherwise over-promise, because having seen that happen many times in the oil and gas industry, it comes back to bite in the end. Investor trust once broken is hard to retrieve. Better to be honest about risks up front even if there are short term costs to that. Investors are surprisingly flexible when it comes to risk, but trustworthiness is something they insist upon, so without making any presumptions, any temptation to “over-egg” is good to avoid. To be clear I’m not aware of any specific projects where this is being done. I’m just making a generic point – applicable to all subsurface resource science – that we do have to watch ourselves sometimes and keep our eyes on the caveats as well as the technical potentials that so excite us. In the throes of an exciting new project that can sometimes be harder than it sounds, even for the most seasoned of us.
The reality though, whether we like it or not, is that commercially speaking geothermal will not always be the best option. I do believe there are many many more places where it has a role, but it always comes down to doing the math. Solar and wind (amongst others) can be great options and their technologies are not standing still either. Technically geothermal is approaching a space where it can be done anywhere, but whether doing so is in fact the best option for our customer – that is a much trickier and much more involved question. Recognition that a vast pool of energy sits down there below us is not enough. It is true though – it is hard to ignore. There are however many vast pools of energy occupying our planet. The cheapest, cleanest, most reliable ones to harvest – that’s the chase. Geothermal is in that space, but it’s a shared one.
A recurring issue I see repeating over and over in country after country is just how much of the geothermal issue revolves around telling the story of existing resource. In the UK there is a great wealth of onshore drilling – mainly for hydrocarbons – but also shallower water boreholes, and there is a lot of onshore seismic to go with it. Yet the packaging of all this data for a purely geothermal use is surprisingly difficult to construct, and resides in a large variety of different coffers. Ask to speak to the BEIS (~UK Dept of Energy) person responsible for geothermal data or licensing protocols and you will encounter a lot of genuine willingness to help, but no one person with any such responsibility. Often licensing is embedded at more local government levels.
This, in an advanced OECD country with decades of subsurface exploration. Imagine then how much more difficult it might be in places with less resource to throw at such database management. Countries truly trail-blazing on this front at the minute are Denmark and the Netherlands. Germany and France also. Lots of places are good at geothermal exploitation, but those that are good at putting the information out there in a way that is easy for investors and their technical teams to pick up and run with, are a lot rarer. This needs to happen as a prerequisite if technical teams are to have the information they need to assess and the convey the scale of resource back to governments. It’s a little bit chicken and egg. I take the view that government is quite busy at the moment, so it is probably the technical community that has to set this ball rolling in a way that government can pick up later.
Such database management is not only critical at the stage of exploration, but also at more mature stages of development. That is to ensure that any licences issued do manage the resource effectively and legally and do not cause negatively impacting interference between projects. Some countries such as Netherlands are now reaching this stage of deployment.
Reservoir thermal energy storage and hybrid renewable projects
In a world where hydrocarbon margins used to be huge and where awareness of climate change issues was not what it is now, there was little incentive to share information or to hybridise across different energy industries. In situations where profit margins across the energy table, even in oil and gas, are looking much closer to bone – the incentive to catch things that might improve project economics anywhere they can be found – is increasing. That is a good thing. Don’t we all hate it when three different utilities dig up our main roads in turn to lay three different things at different times, with three times the disruption, when they are all happening in a similar place at similar depth. It may be a forced analogy, but there is a good case for thinking laterally with other energy players in energy projects these days.
In geothermal, I think it is especially helpful to recognise that it does not have to be the whole solution to be a useful part of it. For any processes that require heating, geothermal doesn’t have to provide all of it to provide a useful component of it. Pre-heating things with geothermal energy before solar or wind or other kick in to provide the rest, may be a useful contribution in many places. That’s worth thinking about whenever we see a good site for any of them. Can the other renewables help too – is an increasingly useful question to ask.
Increasingly the science of thermal energy storage is being applied as well. This is the idea of using a subsurface aquifer or reservoir as a heat bank from which we make heat deposits and withdrawals for later use – perhaps when renewables in hybrid projects are having an “off day”. It depends on the thermal sealing (i.e. insulating) and conducting behaviour of real rocks. Ideally what we are looking for is a “thermal conductivity sandwich” within the geological section, This involves a heat reservoir where we can deposit and withdraw heat (producer-injector doublets again) and insulating rock blankets above and below limit the heat dissipation. Typically, this needs to happen in shallower reservoirs above any deeper geothermal resource (that can also contribute heat to the storage system).
There is then, any time we drill deep to explore a deep geothermal reservoir, an additional opportunity to examine in detail the thermal character of the overburden above, and check out whether it just might be another resource we can exploit. The effectiveness of such reservoir thermal energy storage (RTES) is a developing science, but it is an easy low hanging fruit to check out on the way down with the drill bit – given we are passing that way already.
Geographical potential and the element of scale
It seems fitting to repeat in closing the mantra I repeat over and over again – of scale – i.e. repeatability and delivering size of reward. It is the difference between fine artisanal wines enjoyed locally and mass-produced wine exported and consumed globally. One might be beautiful and a treasure to behold, but which is going keep the bread and butter on the table and the vineyard’s bank manager happy? So too with geothermal. The transition from great standalone individual projects doing fantastic technical work, to one where multi-project potential is recognised and strategically incentivised by public-private partnerships requires this step.
It is my perception that the trajectory to accomplishing this is less one of technological advance and more simply one of communication. People get that there is a resource. They just don’t get the path to monetising it long term. Everything we can do to assist that as technical people will help take geothermal to the newer levels it deserves. It might not be a golden panacea for everywhere, but it does deserve more routine consideration that it currently receives. That is not to suggest communication hasn’t been attempted by the geothermal community previously – it surely surely has – but the appetites for renewable energy now are at a new juncture, and it’s time to get the storyboards out again. More than that, increasingly we can point to many real examples around the globe of where it is working and say to investors – this is no longer new.
What has been hardest in transitioning to geothermal (so far?).
I will finish with a more personal question. I have been asked by some in the audience what I have found hardest about transitioning from oil and gas and into the donning of an additional geothermal hat. I would stress first-up that the transition is not complete, and opinions on whether I have made it yet may vary.
The simple answer to that question is the level of commercial complexity and customer requirements that have to be considered very early on in any project, right from the early exploration stages. That is difficult. Not always very computationally difficult – but as a necessary habit to get into before we get too carried away with our technical story – it does take a mind reset. I mentioned customer driven exploration in the PIVOT 2020 discussion, and for any geoscientist I think that is the hardest element to fully take on board.
Recognising the idea that doing the best geoscience job possible is not always the main requirement for project success, is non-intuitive for a subsurface resource. However, if you are not also looking at the customer from the very first day you start looking at the rocks, then you have vastly diminished your chances of success. Getting to grips with all the myriad aspects of that – subsurface geotechnical, surface engineering, commercial, environmental, regulatory, social, and legal, and not just for geothermal but for the customer’s competing alternatives – is I think the biggest challenge for geoscientists wanting to transition. The reduced margins dictate that this has to happen. It may not involve becoming expert in all those things, but it does involve perceiving enough to know what you don’t know, and who to pick up the phone and call in order to find out. Geothermal has many moving parts. Oil and gas of course does too, but with geothermal more of them have to be engaged earlier to optimise chances of success.
One for you?
To anyone wanting to make the transition, please don’t be too daunted though. I would encourage it – it is truly fascinating technically in ways I hadn’t fully appreciated. I would caution against thinking it is a quick and easy transition though. If you are contemplating it, allocate it the time and perseverance it deserves. It has no shortage of issues, but the sense of being in an industry that is growing and growing for the best of reasons – is invigorating.
My thanks again to all the PIVOT2020 team, especially Philip Ball and Jamie Beard, and also thanks to Glen Burridge for an enduring role as subsurface and energy catalyst. All the unforced errors are mine alone. I should also thank the many scores of people I have discussed the topic with over the past four years. The steady supply of professionals eager to share is one of the subject’s joys. .
Re-published with permission.