Beyond ORCs: Water’s Role in Next-Gen Geothermal Power — A Conversation with Daniel Dichter of Quaise Energy
Amid rising electricity demand, next-generation geothermal systems, such as Enhanced Geothermal Systems (EGS) offer the potential to supply clean and firm power.
EGS enable the extraction of geothermal power in geologic settings challenging for conventional geothermal (i.e., regions without sufficient heat, fluid, and permeability). In EGS, permeability is improved typically via fracturing, and fluid flow is increased by drilling injection and production wells into the subsurface. Hot water and/or steam is then produced to the surface and can be used to generate electricity either in a binary cycle power plant or in a steam turbine (as in dry steam and flash steam power plants).
Dry steam power plants use steam to spin turbines connected to generators whereas flash steam plants convert hot water to steam to drive turbine-generators. Flash steam power plants are more common than dry steam plants (the only dry steam plants in the United States are at The Geysers in northern California) and are used in high-temperature geothermal reservoirs (temperatures greater than 182°C).
In a binary cycle power plant, geothermal fluid heats a secondary liquid with a low boiling point inside a heat exchanger. The geothermal fluid transfers its heat to this working fluid, which then vaporizes. The resulting vapor drives a turbine connected to a generator, producing electricity. Binary cycle power plants are typically used for lower temperature resources (107-182°C), and have also been regarded as superior to dry/flash steam plants due to their ability to utilize highly contaminated geofluid.
As part of next-generation geothermal development, superhot rock (SHR) is drawing increasing attention as a resource found at or above the supercritical temperature of water, (374°C in de-ionized water or higher in brine). Accessing this high-temperature, high-pressure rock can deliver dramatically more energy than conventional geothermal; early SHR geothermal wells have demonstrated 5-10x the MW output of conventional geothermal wells.
Yet there are a number of critical engineering challenges that must be overcome in order to tap into this energy-dense resource. Power plant design is a key R&D priority for SHR environments. In CATF’s “Gaps, challenges, and pathways forward for superhot rock geothermal: summary report” presented at Stanford’s 50th Workshop on Geothermal Reservoir Engineering in February 2025, it was recommended that future R&D prioritize lowering the cost of power plant systems and developing innovations that enhance the durability of equipment under high-temperature, high-pressure conditions.
A paper also presented at Stanford’s 2025 Geothermal Workshop, “Water-Based Geothermal Binary Cycles” highlighted the potential of water-based binary cycles for SHR conditions. Daniel Dichter, the author of the paper and Senior Mechanical Engineer at Quaise Energy, wrote about the potential of water-based binary cycles, where geofluid transfers its heat to pure water through a closed heat exchanger, generating clean steam to drive a turbine-generator. He arrived at the significant conclusion that in high-temperature resources, water outperforms most hydrocarbons used in Organic Rankine Cycles (ORCs) and offers other safety and cost advantages.
Dichter found that water’s higher critical temperature and non-retrograde condensation (i.e., typical condensation) enable it to achieve greater efficiency (22-27%) and resource utilization (61-75%) compared to conventional ORCs for high-temperature resources (300-350 °C). This superior performance translates into lower power plant costs:
Fewer wells are required. As stated in the paper, the cost of wells scales with the geofluid production rate. Because higher utilization means less geofluid flow is needed for the same power output, fewer wells are necessary at high temperatures.
Smaller, less expensive heat exchangers. Heat exchanger cost is proportional to the heat transfer rate, which Dichter shows is lower for water than for organic working fluids. This translates into smaller, cheaper heat exchangers.
Smaller, less expensive condensers. Similarly, condenser cost is proportional to the heat rejection rate, which is also lower for water, resulting in smaller, cheaper condensers.
Regarding working fluids, the hydrocarbons used in ORCs are expensive (10-50 $/gal), toxic, and usually flammable. Thus, they require specialized safety equipment and can necessitate onerous operational procedures, which can prohibit the development of a project. In contrast, water is usually less than 0.01 $/gal and is both non-toxic and non-flammable.
I was excited to sit down with Daniel and learn more about his research and the significant potential for water-based binary cycles for SHR applications. The full interview from August 20th is below. Please note that interview responses have been paraphrased/condensed for clarity.
First, I would love to learn more about your background and your roles at Commonwealth Fusion Systems (CFS) and Quaise Energy. How have your education and experiences inspired your research for water-based binary cycles?
I actually started out in aerospace and then joined CFS, where I did the early engineering work on the current feeder system of SPARC. In 2022, Quaise came onto my radar, and I’ve been here since then.
At Quaise, most of my focus has been on what happens after drilling. The company is tackling what’s arguably the single biggest bottleneck in geothermal: developing the drilling technology itself. My interest has really been in superhot rock and figuring out what we actually want to target once that drilling tech is in place.
If you look back, the development of geothermal power plants spans over a hundred years, but the “playbook” for higher-temperature resources hasn’t really been written yet. Up to about 250-300 °C, there are established norms for plant design. Beyond that, though, it’s largely uncharted territory, and that became the initial impetus for this line of research.
In 2024, I wrote a paper for the Geothermal Rising Conference (GRC) that took a broader look at high-temperature power plants. In that work, I touched on water-based cycles. The Stanford paper I presented in February is meant as a sequel, diving deeper into that specific aspect of the GRC paper, and exploring the possible technologies we could actually deploy for SHR.
There are also some strong analogs between water-based binary cycles in geothermal and certain approaches in nuclear fission power plants, which is another angle I’m excited to keep exploring.
What specific limitations of ORCs stood out to you as motivating factors for exploring water cycles?
Working fluids for ORCs are toxic and usually flammable, with a chemical composition that’s similar to gasoline. While there are definitely other industrial fluids that are more dangerous, from an environmental standpoint, they’re not great. They’re also expensive relative to water. The reason we use them anyway is that for certain applications, they work remarkably well from a thermodynamic perspective.
Another piece of it is commercial maturity. ORC technology, while groundbreaking in a sense, is nowhere near as developed as the huge ecosystem of water-based machinery that already exists. ORCs are more of a duopoly; only a couple of companies in the world really make them. Steam turbine technology, on the other hand, is much more diversified, more mature, and has been deployed at scale for a long time.
So ORCs are great for certain things, but they come with real drawbacks too.
Could you explain in simple terms how a water-based binary cycle differs from an organic Rankine cycle?
The key idea in both cases is that we’re not using the geothermal fluid directly. You have a heat exchanger in between, so the heat gets transferred without the fluids mixing.
In a conventional ORC, that heat gets transferred into a hydrocarbon working fluid (often butane, pentane, sometimes cyclopentane). In the water-based binary approach, it’s water on both sides — basically water-to-water heat exchange.
You state that water-based binary cycles offer a compelling alternative compared to ORCs in high-temperature environments, particularly where the development of flash or dry steam power plants is not feasible. Could you expand more on the conditions that would preclude the development of these systems? How do they compare to binary cycle power plants in terms of efficiency and costs?
Geofluid always contains impurities including things like salt, silica, and carbon dioxide. The solubility of these impurities tends to increase with temperature, so hotter geofluid tends to be “dirtier” and harder to handle. Flash and dry steam plants use the geofluid directly, so they’re more vulnerable to adverse effects from these impurities. The heat exchanger of a binary plant is a nice feature because it protects the rest of the plant from these effects. In some cases, a binary plant is the only practical way to utilize the geofluid.
Binary plants tend to be more expensive upfront, but they run much more cleanly and require less maintenance. Binary and flash cycles are of remarkably similar efficiency, so the difference between them is more about practical things like cost, maintenance, and reliability.
ORCs are often considered easier to deploy at small scale. Do you see water cycles mainly as a solution for larger, utility-scale plants?
Yes. If you look at unit sizes, ORCs max out around 20-30 MW, and they’ve only been creeping upward since the 1980s. Steam turbines, by contrast, go all the way up to gigawatt scale, and they can also scale down into the tens or hundreds of megawatts.
So steam turbine technology covers a much wider range of sizes. As plants get larger, it just makes more sense to move toward those bigger units, which naturally synergizes with steam turbines rather than ORCs.
In the paper, you mentioned that turbine size is sometimes a concern: how big of a challenge is turbine design compared to the benefits water brings?
In the literature, I’ve come across a few claims comparing ORC turbines to steam turbines, suggesting that water is a non-starter as a binary cycle working fluid. But when you actually analyze it, turbine size really isn’t a showstopper for water-based systems.
Yes, steam turbines do tend to be larger with bigger diameters, more stages, and the vapor is a lot more compressible, which adds complexity. But that’s a challenge the industry has already shown it can solve. So compared to the benefits of using water, turbine design isn’t a barrier.
Cost, safety, and scalability seem to favor water. What are the biggest barriers to adoption of water-based cycles today?
The main barrier is temperature. In my paper, the number I came back with was that you really need production temperatures of at least 300 °C before water-based cycles become roughly competitive with ORCs. The industry hasn’t been able to consistently reach that yet. There are flickers that it’s possible (Iceland is a good example), but it’s not broadly proven yet.
The other factor is scale. As the capacity of a well field increases, water-based systems become more attractive because the unit sizes can get larger.
So it really comes down to how high a temperature resource we can develop, and how broadly we can develop it. The “how” and the “when” are the more complex questions.
If a developer had to choose between building an ORC plant or a water-based binary cycle plant at 300-350 °C, what would the payback or cost advantage look like in practice?
That’s actually a key question we’re working on right now. Quaise is in the process of raising funds to start a project in the Northwest U.S., and we’re looking at both paths in parallel. Either way, you end up with a working power plant, but the question is which option delivers the better economics. Unit sizing is a big part of that, along with a host of other factors.
There will be applications where ORCs make more sense, and others where water-based systems come out ahead. My view isn’t “water-based or bust.” It’s about having an additional tool in the toolbox, because in the end you’re always going to want to build the plant that gives the best economic returns.
We’re looking at both the upfront costs and the levelized cost of electricity. But to some extent, you can’t really know the answer until you’ve got a geothermal asset actually producing. Long-term flow conditions matter a lot, and the details of plant design are still actively being developed.
How do you see policy, regulations, or safety standards influencing the choice between ORCs and water cycles?
Policy and regulations matter, but the social factors are just as important. If I had to choose which kind of power plant I’d want next door, I’d probably favor a water-based cycle.
A lot of ORCs today are being built in the Southwest on BLM land, which is pretty far from communities or towns. But as projects start moving closer to where people actually live, the choice of technology becomes more visible and more relevant.
Ultimately, if the people around a project site don’t want it to happen, there’s a good chance it won’t. So any project has to consider the social impact on the immediate community. That’s a really important point.
As you mentioned briefly above and as stated in your paper, water-based binary cycles are used for nuclear power generation. Could you expand on this? What other opportunities are there for tech transferability between the nuclear and geothermal fields?
Yes, I believe that SHR geothermal could end up looking quite a bit like PWR (pressurized water reactor) fission, which is the most common type of nuclear power plant. In a PWR, the reactor core is continuously cooled with liquid water, which is then used in a water-to-water heat exchanger (called a steam generator in the industry) to produce clean steam for a steam turbine.
The temperatures and pressures seen in PWRs are remarkably similar to those that are possible with SHR geothermal, so I see the reactor core as being significantly analogous to a SHR geothermal reservoir. That means there’s potentially a lot of overlap, especially in the areas of the heat exchanger and turbine design.
What role do you see water-based systems playing in the future of superhot rock geothermal development?
Superhot rock geothermal is a unique resource, and there are a lot of people who would benefit from seeing it developed. We’re doing our part to help open up the bottleneck around drilling, while other companies are working on pieces like wellbore completions and stimulation. It’s really a suite of technologies that all have to come together.
Once that happens, SHR could be an incredible asset: very power dense, environmentally benign, and extremely promising as a long-term energy source. My hope is that we are successful in bringing this vision to fruition.