Reflections from the 2022 Geothermal Rising Conference

September 6, 2022 · Mark McClure

I attended the Geothermal Rising Conference last week in Reno, NV. In this blog post, I recap observations from the conference and about the geothermal industry, in general. This article focuses on topics that are related to my own professional work – Enhanced Geothermal Systems (EGS) and deep-closed loop heat exchangers (Wang et al., 2009; 2010; McClure, 2012; McClure and Horne, 2014a; Shiozawa and McClure, 2014; Li et al., 2016; McClure, 2021a; 2021b; Fowler and McClure, 2021; McClure et al., 2022).

For full disclosure: either ResFrac or I personally have worked with several of the companies/projects discussed in the article: Utah FORGE, Fervo, GeoX, Criterion, and the EGS Collab Project.

This is an exciting time for EGS. Multistage hydraulic fracturing has tremendous potential to improve the productivity of geothermal wells in low permeability formations (Gringarten, 1975; Cremer et al., 1980; Green and Parker, 1992; MacDonald et al., 1992; Jung et al., 2013; Glauser et al., 2013; Shiozawa and McClure, 2014; Li et al., 2015; Lowry et al., 2014; Olson et al., 2015; Doe and McLaren, 2016; McClure, 2021b; McClure et al., 2022). Projects are happening right now to test this concept in full-scale EGS wells. If they prove successful, we could soon see a major increase in geothermal energy production.

Historically, EGS projects have been affected by flow localization, where injection stimulates only one or a few major flowing pathways. This limits the total flow rate through the system and leads to thermal breakthrough and inefficient heat sweep efficiency. In contrast, multistage stimulation with limited-entry perforating can create hundreds of major flowing pathways along a lateral (Raterman et al., 2017; 2019; Ugueto al., 2021). When applied to EGS, multistage stimulation is expected to increase the total flow rate and mitigate thermal breakthrough, resolving the key problems that have limited EGS development in the past.

The FORGE project, operated by the University of Utah and sponsored by the US Department of Energy, has successfully drilled its first horizontal well, 16(A), and performed a stimulation of their first three stages. Next year, they will be drilling an offset well, 16(B), and stimulating the remaining intervals along 16(A). In addition, FORGE is sponsoring a variety of research projects around the country, developing technologies that will enable growth in geothermal energy production. Many of these projects gave updates at the GRC meeting.

Already, the project has yielded impressive accomplishments that will have a significant impact on the geothermal industry. For example, the drilling of 16(A) accomplished record-breaking rate of penetration and bit life for a well drilled through granite. Because the project is publicly funded, the innovations behind these improvements are being shared broadly with the geothermal community (Samuel et al., 2022).

By this time next year, the second FORGE well will have been drilled, the first well will have been fully fractured, and circulation tests will have been performed between the two wells. Key metrics to watch – what is the circulation rate achieved between the wells, and how distributed and/or localized is the distribution of flow?

The future fracturing tests from well 16(A) will be performed after the drilling of offset well 16(B). The 16(B) well will have fiber optic installed outside the casing, which will allow imaging of the location and orientation of each individual fracture intersection with the 16(B). This is exciting because it will give us an unprecedented look at the far-field fracture geometry and the ‘mechanism of stimulation,’ which is a key technical issue when modeling and engineering EGS stimulations (McClure and Horne, 2014a; 2014b; McClure et al., 2022).

Another full-scale EGS project with multistage stimulation is being performed by Fervo Energy. They have completed drilling and stimulation of their first well and are currently drilling their second well to intersect the fractures created by the stimulation of the first. A few weeks ago, they announced a fund-raising round of $138 million. They have a super talented team, an extremely promising technical approach, and the resources needed to execute!

GeoX gave a presentation at GRC on their plans for an ultrahigh temperature EGS project (>350˚C). The company is led by drilling engineers with deep O&G experience in high-pressure/high-temperature projects. They are developing specialized technology and approaches to tackle the unique challenges of drilling and stimulation at very high temperatures. Ultrahigh temperature is attractive because the electricity production per well can be extremely high (because of much higher enthalpy of the fluid and the higher efficiency of conversion to electricity).
AltaRock is another important EGS company targeting ultrahigh temperatures. They are led by a team with years of experience in geothermal and EGS.

Criterion Energy Partners recently acquired a large geothermal lease along the Texas Gulf Coast targeting medium temperature geopressured sedimentary resources. The advantage of targeting sedimentary resources is that there are abundant formations with good matrix permeability. This increases the consistency of well performance and allows fluid to flow more uniformly through the formation, relative to reservoirs that depend on flow through fractures. Nevertheless, hydraulic fracturing can still be very useful in medium or high permeability sedimentary formations. Relatively smaller fractures are created around the wellbore to reduce near-wellbore pressure drop and improve the connectivity of the well to overlying and underlying layers.

Deep Earth Energy is also targeting geothermal in sedimentary formations. They have already drilled a pilot well and are planning a larger development. They used multistage fracturing in their first well, but they said at GRC that they do not plan to use fracturing in their upcoming wells. Because of the good natural permeability of the formation, they believe they can achieve sufficient well productivity without expending CAPEX on fracturing.

The EGS Collab is a Department of Energy-funded research project performing mesoscale stimulation experiments. The project utilizes wells drilled 100s of feet off mine shafts at depths of 5000-6000 ft. Because they are drilling off a mine shaft, it is cost-effective to drill numerous instrumented ‘observation’ wells, allowing high-fidelity imaging with microseismic and other techniques.

At the GRC, Kneafsey et al. (2022) presented interesting new results from the project. In their ‘Phase 2’ experiments, they identified fractures along the borehole that should be ‘critically oriented’ to slip at elevated pressure. They set packers instrumented with strain gauges around each fracture and injected at low rate to increase pressure close to Shmin, but to not exceed it. At this elevated pressure, the stress analysis predicted that they should slip. But instead, none of the fractures slipped, and there was not an observed increase in injectivity. Next, they injected at higher rate, causing pressure to exceed Shmin, and stimulation occurred readily as newly forming fractures began to propagate through the formation.

The test design and results were similar to experiments performed at the FORGE project earlier this year (shortly before the beginning of Stage 1 in the openhole section of 16(A)), and at the Desert Peak project in 2011 (Chabora et al., 2012; McClure et al., 2014b). These experiments demonstrate that being critically stressed at elevated pressure is a necessary but not sufficient condition for shear stimulation to occur on natural fractures. The results support an argument that I have been making for years – that shear stimulation is not the primary mechanism of stimulation in many or most EGS projects, and that propagation of newly forming fractures is nearly ubiquitous in EGS (McClure, 2012; McClure and Horne, 2014a; 2014b).

Many ‘DFN’ style modeling codes have assumed that hydraulic fractures terminate against preexisting fractures because of mechanical interference (Weng et al., 2011). However, in both ‘Phase 1’ and ‘Phase 2’ of the EGS Collab projects, the results suggest that the hydraulic fracture growth was limited by leakoff into the (relatively small fraction of) natural fractures that are already hydraulically conductive prior to stimulation (Fu et al., 2021; Kneafsey et al., 2022). Conversely, hydraulic fractures propagated directly across the non-conductive, cemented natural fractures, without indication of mechanical interference. This suggests that we should shift our thinking on ‘hydraulic fracture termination against natural fractures’ – that it is driven more by ‘leakoff’ than by ‘mechanical interference.’

There were several deep closed-loop heat exchanger companies giving presentations and/or booths at GRC. In the past, I have expressed great skepticism on this concept (Wang et al., 2009, 2010; McClure, 2021a; Fowler and McClure, 2021). Since then, I haven’t seen anything to change my mind. The basic problem is that downhole heat exchangers (typically) rely on heat conduction to bring energy into the well. Heat conduction is very slow, and so the energy produced per ft of wellbore is low (Morita et al., 1992; Nalla et al., 2004; Wang et al., 2009; 2010; Oldenburg et al., 2015; McClure, 2021a; White et al., 2021; Beckers et al., 2022). Drilling is a key driver of cost for geothermal, which means that downhole heat exchangers produce energy at very high cost, ballpark 10-100x more expensive than energy produced from conventional geothermal.

The closed-loop companies are aware of the ‘slow heat conduction’ problem, and so they are proposing different variations in an attempt to improve the economics. Having listened carefully to what they are saying, it appears to me that the deep closed-loop heat exchanger designs currently being proposed either: (a) require revolutionary decreases in the cost of drilling to be affordable, (b) cannot scale beyond niche applications, and/or (c) will not produce as much energy as hoped.

Also, many of the proposed designs will be extremely challenging operationally. It remains to be seen if they can be executed in practice. But even if they can, they will prove to be an extremely expensive way to produce energy.

The GRC had a panel discussion on the technoeconomics of closed loop. One of the panelists made an important point that is worth repeating – closed loop heat exchangers cool down the rock, and so they have the potential to induce seismicity (Segall and Fitzgerald, 1998; Jacquey et al., 2015; Rutqvist et al., 2015; Martinez-Garcon et al., 2020). Closed loop geothermal companies have claimed that they have ‘zero’ risk of induced seismicity, and this is simply not accurate. As with EGS, induced seismicity isn’t a show-stopper, but it is important that projects perform an induced seismicity hazard assessment and follow the best-practices protocol from Majer et al. (2012).

One closed-loop company at GRC said that they want to start installing downhole heat exchangers in depleted oil and gas wells. In my opinion, this could not possibly recoup the cost of the insulated tubing, installation, surface facilities, O&M, and overhead. In a typical oil and gas well, a downhole heat exchanger would yield, at best, a few tens of kW of electricity (ie, a few $10,000/year of revenue).

The usefulness of downhole heat exchangers in oil and gas wells appears to be a point of confusion in the literature. A recent journal publication on this topic projects 1.5-3.5 MWe of power potential for typical oil and gas wells, concludes the idea has “great potential,” and gives a preliminary ballpark estimate of 44,000 MWe of potential, just from the Eagle Ford shale alone (Livescu and Dindoruk, 2022). Unfortunately, this study used unrealistic assumptions regarding heat transport and power plant efficiency and arrived at electrical power projections roughly 100x higher than could be achieved in practice.

There is an interesting opportunity to use certain oil and gas wells to produce geothermal energy, but it is not from using downhole heat exchangers. Instead, engineers could identify wells that are already capable of producing high volumes of fluid (typically at high water cut) at reasonably high temperature, and simply connect surface equipment to the hot water that is already freely available at the separator (Augustine and Falkenstern, 2012; Brus, 2022).

The topics discussed in this blog post only scratch the surface of all the interesting things happening in the geothermal space right now, and only cover a fraction of the work that was presented at GRC. It is an exciting time for geothermal!


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