Yesterday, Fervo Energy announced the results from their ‘Project Red’ pilot in northern Nevada (Norbeck and Latimer, 2023; Ma, 2023). The results are spectacular.
For nearly 50 years, the goal of Enhanced Geothermal Systems (aka, Hot Dry Rock) has been to convert low permeability, hot formations into economically viable geothermal reservoirs (Murphy et al., 1977). Success has been elusive. During stimulation, flow tends to localize into a small number of fracture pathways. This limits the flow capacity and heat sweep efficiency of the resulting reservoir. The most successful EGS projects, such as the project at Soultz, have depended on stimulating large preexisting faults. This approach is not scalable because it relies on finding large faults in the subsurface; even so, projects targeting large faults have not quite reached target circulation rates (Genter et al., 2013).
Fervo recently completed a 37-day crossflow test between a pair of wells at their Project Red pilot. Each well has a 3000 ft lateral, stimulated with plug and perf multistage fracturing. As shown in Figure 6 from Norbeck and Latimer (2023) (reproduced below), the wells achieved by far the highest circulation rates ever circulated between EGS wells, greater than 60 L/s. Just as important, Figure 15 from Norbeck and Latimer (2023) (reproduced below) shows that the flow distribution was fairly uniform along the 3000 ft lateral (as measured by a spinner log during circulation). Flow uniformity is critical for the thermal longevity of the system, because it prevents premature thermal breakthrough due to flow channeling.
Higher flow rates could be achieved in the future by using a longer lateral (10,000 ft is the most common length for shale wells, and these wells had only 3000 ft laterals) and by drilling a series of wells, rather than just a doublet (so that fluid can flow in both directions between the wells, rather than in just one direction). Unlike the previous ‘best’ EGS systems, such as Soultz, the Fervo wells were drilled in a tight formation with no evidence of significant preexisting faults. Also, the production well in the Fervo pilot was not pumped; instead, it was produced solely from reservoir pressure created by the injection well. Many past EGS production wells have relied on artificial lift to increase rate.
Production rate is affected by factors such as well spacing, fracture height, the number of fractures, and the number of wells. So, we can predict production results for hypothetical changes by calculating the apparent fracture conductivity. If we know conductivity, then we can plug into Darcy’s law and calculate a quick estimate for flow rate under different well configurations. Norbeck and Latimer (2023) estimate conductivity by calculating the difference in BHP between the two wells during steady-state circulation (accounting for factors such as wellbore friction), and then plugging into Darcy’s law, considering the fracture height, well spacing, etc. Assuming 75-100 flowing fractures connecting the wells, they calculate a conductivity of 300-400 md-ft for each fracture.
In my past work modeling EGS circulation, I have always viewed fracture conductivity during long-term EGS circulation as a key uncertainty, one that has a major impact on project economics (Shiozawa and McClure, 2014; McClure et al., 2022). 300-400 md-ft per fracture is at the upper range of what I would have hoped for. This conductivity is higher than necessary – models suggest that you could have significantly lower conductivity, and still achieve economic performance. Multistage fracturing creates so many flowing fractures that even moderate fracture conductivity can add up to become a very high total flow rate per well.
For comparison, measurements in shale suggest that fracture conductivity when wells are first put on production (POP) often exceeds 100 md-ft in well-to-well interference tests (Almasoodi et al., 2023). During long-term depletion, pressure is drawn down by 1000s of psi and the conductivity can decrease by 1-2 orders of magnitude. But in an EGS system, the injection well permanently sustains reservoir pressure – there is never widespread depletion of reservoir pressure. Thus, as observed in the Fervo pilot, conductivity during circulation can be quite high – the same order of magnitude as the conductivity that we measure at POP in a shale well. Further, EGS wells will usually be landed in high-strength, low-clay formations, which should lead to higher fracture conductivity (either propped or unpropped), relative to the typical shale formations.
What’s different about Fervo’s approach? A radically different and more modern stimulation design.
In the 1980s, the HDR/EGS community embraced the hypothesis that ‘shear stimulation of natural fractures’ would be able to create a dense, distributed flow network from stimulation (Pine and Batchelor, 1984; Murphy and Fehler, 1986). This hypothesis has not been borne out by subsequent experience. While injection does sometimes induce shear stimulation of natural fractures, flow tends to be localized to only a small number of these fractures (Baria et al., 2004; Evans et al., 2005). In many (or most) cases, the evidence suggests that hydraulic fracture propagation is the dominant mode of deformation (McClure and Horne, 2014; Norbeck et al., 2018). The pursuit of a dense network of shear-stimulated natural fractures has led to stimulation designs that would be considered uneconomic if applied in an oil and gas setting – a single fracturing stage, a vertical well, and no proppant.
Fervo applied the learnings of the shale industry to EGS. They utilized a plug and perf multistage fracturing treatment. Their cemented fiber measurements demonstrate that they achieved a virtually 100% perforation efficiency – breaking down the formation and creating fractures at every perf cluster – spaced at 25 ft (Norbeck and Latimer, 2023). As we’ve learned from recent core-through studies in shale, it’s likely that the true fracture spacing is even tighter than the cluster spacing (Raterman et al., 2017; 2019; Gale et al., 2018; Ugueto et al., 2019).
Multistage fracturing concepts date back to the earliest days of hot dry rock (Gringarten et al., 1975; MacDonald et al., 1992; Green and Parker, 1992). But over the past 25 years, the oil and gas industry has dramatically improved the efficiency and performance of multistage fracturing – improved downhole tools, better surface efficiency, a better supply chain, and better fracture designs.
A decade ago, when I would discuss multistage stimulation for geothermal wells with colleagues, the common response was that it wasn’t technically feasible – supposedly, we didn’t have plugs or packers capable of sealing the wellbore in these high-temperature formations and large-diameter wellbores. This is why, for example, the AltaRock project at Newberry used diverters instead of mechanical isolation devices (Cladouhos et al., 2015).
Sogo Shiozawa and I did a deep-dive on this topic as part of a paper in 2014, reviewing literature and talking to companies like PackersPlus (Shiozawa and McClure, 2014). We realized that packers and plugs existed off-the-shelf that could function in geothermal wells, but they would only work inside a cased well. Openhole plugs/packers are much more difficult to design because the hole geometry is less reliable. But conventionally, EGS folks wouldn’t consider plug-and-perf completion in cased/cemented wells because they were focused on shear-stimulating natural fractures. Fast forward to today, and now there is wide recognition that high-rate injection is primarily causing opening mode fracturing, rather than shear stimulation, in both geothermal and oil and gas (McClure and Horne, 2014; Fu et al., 2021; Raterman et al., 2017; 2019; Gale et al., 2018; Ugueto et al., 2019). In the shale industry, plug and perf designs (which use cementing casing) have almost entirely replaced openhole swellable packers.
Ten years ago, talking to colleagues, I would hear: (a) we can’t drill horizontal wells at high temperatures in hard rock, (b) even if we did, the plugs wouldn’t hold during multistage fracturing, (c) even if they did, we couldn’t break down the formation from a plug and perf completion, and (d) even if we did, the stimulation wouldn’t succeed if you cemented off the natural fractures. Fervo proved all of that wrong!
It’s an incredible accomplishment for the Fervo team. They’ve carried a huge lift – persuading investors to back their approach, building a team, identifying sites, performing subsurface engineering to design the system, and then executing the drilling, well construction, and stimulation.
The Utah FORGE project is close behind. They have performed a few small-scale stimulations in their Well 16(a), and their commercial-scale fracturing stages will occur early next year. In parallel, Fervo’s next pilot is being drilled right now – next door to FORGE, and it will be stimulated around the same time.
I think it’s important to note – without the FORGE project, there probably would have never been a Fervo project. The first FORGE FOA was released by the DOE Geothermal Technologies Office in June 2014. The FOA specifically stated that the DOE intended to pursue multistage stimulation along a horizontal or highly deviated wellbore. This was the first time, to my knowledge, that any major entity associated with geothermal energy had put its weight behind this approach. The DOE’s support gave credibility to the concept, and I believe this was critical for getting Fervo off the ground a few years later.
The FORGE site-selection process resulted in the gathering and publication of high-quality site characterization for potential EGS sites across the country. Since then, field operations at the Utah site have already achieved important breakthroughs, such as advances in drilling (Samuel et al., 2022). In the future, planned field data collection at FORGE will be invaluable – such as fiber observations in offset wells designed to interrogate the quantity, orientation, and character of fractures intersecting the offset Well 16(b) during commercial-scale stimulation.
In the immediate term, people will keep a close eye on the upcoming stimulations from the Utah FORGE project and from Fervo’s second pilot project, which is adjacent to the Utah FORGE site. Will these projects be able to reproduce the results from Fervo’s ‘Project Red’ – with high rate and distributed flow across the lateral?
Project Red is in a metasediment formation intruded by granitic dikes – typical of many regions across the Basin and Range. The Utah FORGE geology is somewhat similar, but is more of a granitic/gneissic mashup. If these follow-up pilots are successful, then it would be an even more powerful validation of the concept because it would demonstrate that the approach is repeatable.
I am curious to see the commercial response from oil and gas companies. The US shale industry has expertise, manpower, and horsepower that could be directly applied to EGS multistage fracturing. This is an industry that: (a) is facing the prospect of dwindling shale resource quality over the next decade (at least, in the US), and (b) is under pressure to diversify its business model. If EGS field projects continue to deliver successful results, it would seem inevitable that shale companies will become involved in a big way. For example, in April, Devon Energy announced an investment in Fervo (Cariaga, 2023).
In the immediate term, I expect that Fervo will soon be seeking to expand to bigger projects. To reach full potential, they need to test longer wells and alternating series of producer/injectors (so that wells can flow in either direction). They need to do careful work to assess the optimal well spacing. Even as they continue to achieve technical success, they will need to demonstrate the commercial model – that they can secure funding, execute, and drive down costs to achieve long-term profitability.
The breakeven time for these projects will be several years. This is different from the business model that shale operators are accustomed to – with rapid return on investment. However, EGS wells will not experience the rapid rate decline over time that shale wells experience. The injection well maintains reservoir pressure and rate at the production well. The biggest challenge moving forward will be to engineer these systems to sustain high production temperatures for many years – ideally, 20-30 years. As fluid circulates, the rock cools down. If flow is not sufficiently uniform, there could be premature thermal breakthrough, resulting in an early drop in produced temperature. The longevity of the systems will have a significant impact on the economics. Fervo is off to a great start – as shown above, flow is distributed fairly uniformly along the lateral. That’s what they needed to demonstrate.
Very soon, I will post a follow-up blog post on ResFrac simulations that I’ve performed of long-term fluid circulation for EGS. The results yield surprising insights into the interactions between cooling, thermoelastic stress change, crack opening, and crack propagation. I’ve been surprised by the results. Because of interactions between processes, the role of thermal fracturing during long-term circulation is not necessarily as negative as often feared. Under the right conditions, it could play a very positive role.
Some have expressed the concern that flow rates will drop over time because of proppant degradation. Countering this, stress reduction due to cooling over time will tend to increase flow rate over time. Indeed, if we look at past geothermal projects involving long-term sustained injection, wells have consistently demonstrated an increase in injectivity over time (Chabora et al., 2012).
There are many scientists and engineers already racing to develop improved technologies to support EGS. I expect Fervo’s results to accelerate this work. The DOE Geothermal Technologies Office, through FORGE and other initiatives, continues to fund an array of initiatives to develop downhole tools, imaging techniques, proppants, strategies to mitigate thermal short-circuiting, and many more.
Technologies to mitigate thermal short-circuiting are especially interesting. One particularly intriguing concept is to put an ‘inflow control’ on the production wells so that it is impossible for too much fluid to flow into the well at any particular point. I will provide more discussion of this topic in my upcoming blog post.
Fervo has led the way in identifying novel use cases for EGS. Ricks et al. (2022) demonstrated how EGS production/injection could be modulated to help address load balancing on the grid. Fervo also recently announced a project integrating EGS with Direct Air Capture. This is an intriguing idea because DAC can operate directly on the geothermal heat, without converting it to electricity. This could avoid the cost of building a power plant. Geothermal direct use looks great on paper but is limited practically because it needs large demand sources for medium enthalpy water to be collocated with geothermal wells. DAC could provide those large demand sources.
From the ResFrac perspective, I am excited because EGS opens up a whole universe of new modeling questions that need to be addressed. How do we optimize well spacing, both vertically and laterally? How do we account for thermoelastic stress changes and fracturing during circulation? How do we design diagnostics to interrogate the fracture characteristics and draw useful engineering conclusions? What is the best way to optimize load balancing on the grid? Should we consider alternative working fluids, like CO2? We have a lot of work to do…
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