Our states in our backyard just made a bet on geothermal energy, and anyone who specifies or services process equipment in the region should pay attention.
In May 2026, the governors of Utah, Colorado, Arizona, and New Mexico launched the Mountain West Geothermal Consortium, a coordinated push to accelerate permitting, financing, and deployment of geothermal power across the region. Utah’s FORGE research site near Milford has been proving out enhanced geothermal technology for years, and Fervo Energy is already building its commercial Cape Station project in Beaver County. The conversation has shifted from whether this technology works to how fast it can scale.
What makes geothermal compelling for utilities is the word that keeps coming up in every grid-planning conversation: firm. Geothermal runs around the clock regardless of weather, season, or time of day. It does not need fuel deliveries. For a region facing load growth fueled by data centers and population, that reliability profile is hard to argue with.
But from a process equipment standpoint, geothermal is a different animal than anything most of us have been specifying for. The fluids are hotter, more corrosive, and more abrasive than what you encounter in a typical combined-cycle or industrial steam plant. Getting the flow control right is not optional — it is the difference between a plant that runs for decades and one that eats its own internals in a few years.
Conventional power plants burn fuel and make steam from treated water. You control the chemistry. Geothermal plants bring fluid up from a reservoir thousands of feet underground, and whatever is dissolved in that fluid is what you are working with.
In the Basin and Range province that stretches across Utah, Nevada, and Arizona, reservoir brines commonly carry dissolved silica, hydrogen sulfide, carbon dioxide, and chloride concentrations that would be considered a serious upset condition in a conventional boiler system. Silica precipitates out of solution as the fluid cools and pressure drops, scaling valve internals and seats. Hydrogen sulfide is corrosive to carbon steel and many copper alloys. Chlorides attack austenitic stainless steels through pitting and stress corrosion cracking, especially at elevated temperatures.
The combination of high temperature, high pressure drop, and aggressive chemistry means standard carbon steel and 316 stainless steel—the workhorses of most industrial valve applications—do not hold up. You end up specifying duplex and super duplex stainless steels, nickel-based alloys like Alloy 625 or C-276, and in some cases titanium for the wetted parts. Valve trim often needs tungsten carbide or ceramic coatings to resist erosive wear from silica-laden flow.
None of this is exotic for the sake of it. Service conditions drive it, and getting the material selection wrong means unplanned shutdowns and expensive replacements.
The plant architecture determines which valves see the hardest duty, and two designs dominate.
In a flash-steam plant, high-temperature geothermal fluid is brought to the surface under pressure and flashed to steam in a separator vessel. The steam drives a turbine; the remaining liquid brine is reinjected. The steam side uses familiar equipment — isolation valves, turbine bypass and conditioning valves, attemperators, condensate control. But every component on the brine side — separator level control, reinjection throttling, blowdown — sees the full brunt of that aggressive chemistry.
Binary-cycle plants, more common for the moderate-temperature enhanced geothermal resources being developed across much of the Mountain West, keep the geothermal fluid in a closed primary loop. That hot brine passes through a heat exchanger where it heats a secondary working fluid — typically isobutane or isopentane — which vaporizes and drives an organic Rankine cycle turbine. The geothermal fluid never contacts the turbine, and the working fluid circulates in a sealed system.
The valve challenges shift accordingly. The primary loop still sees corrosive, scaling brine and needs the same aggressive material selections. But the secondary loop brings its own problems: the working fluids are flammable hydrocarbons operating near their boiling points, so tight shutoff is critical, and fugitive-emissions requirements drive you toward bellows-sealed or low-emission packing designs. Pressure relief on the working-fluid circuit needs to be sized and set for fluids with vapor pressure curves very different from steam or water.
Most Mountain West geothermal development currently in the pipeline uses enhanced geothermal systems rather than tapping naturally occurring hydrothermal reservoirs. EGS borrows horizontal drilling and reservoir stimulation techniques from the oil and gas industry to create permeability in hot dry rock, then circulates water through the engineered fracture network to pick up heat.
From a flow control standpoint, the good news is that the injected fluid starts as treated water. Hence, operators have more control over brine chemistry than they do with a natural hydrothermal reservoir. The challenging news is that the fluid still picks up dissolved minerals as it moves through the formation, and reservoir management demands exact control of injection rates and pressures to maintain the fracture network without inducing seismicity. That means wellhead control valves on the injection side need to deliver accurate, stable modulation over a wide range of flow conditions, not just open-and-shut isolation.
Instrumentation on the wellhead and surface equipment — pressure and temperature transmitters, flow measurement, and safety-rated shutdown systems — also needs to be rated for the environment. Ambient swings at high-desert and mountain sites can run from well below zero to over 100 degrees Fahrenheit, and many locations are remote enough that reliability between service visits matters more than it would at a staffed plant.
One more development worth watching: direct lithium extraction from geothermal brines. Several projects are working to co-produce lithium alongside electricity by processing the brine stream after it exits the power plant. DLE adds another layer of process equipment demand—chemical injection skids, filtration, ion exchange or sorbent systems—all needing corrosion-resistant valves, precise flow control, and instrumentation rated for aggressive chemical service.
The Mountain West has lithium-bearing geothermal resources of its own. As this co-production model matures, it could add meaningful equipment scope on top of the power-generation side.
Geothermal is not going to replace gas-fired generation overnight. But the momentum behind it in our service territory is real. Utah, Colorado, Arizona, and New Mexico are all states where MSEC works, and the development pipeline is moving from research into commercial deployment.
For engineers and operators specifying equipment for these projects, the takeaway is clear: the material and performance requirements for geothermal service are significantly more demanding than standard industrial or power-generation duty. Severe-service valve expertise, the right alloy selections, and instrumentation that can hold up in remote high-desert environments are not nice-to-haves. They are the baseline.
We have been working with severe-service applications, specialty alloys, and demanding process conditions across oil and gas, chemical, and power generation for over 45 years. Geothermal brings a new combination of those challenges, and we are ready for the conversation. If you are working on a geothermal project or evaluating equipment options, contact us – we would rather help you get the spec right the first time than replace something that wasn’t up to the job.