If you have been working on a conventional rig and then wandered on to a geothermal drilling operation, the first thing that strikes you is how things seem pretty much the same. Same rotary equipment, same basic approach to casing programs, same thoughts about cement barriers, same pressure-control stacks. The second thing that strikes you (usually when something goes wrong) is that some of this equipment is being used in a fundamentally different physical environment than what you are used to. Hot water, natural fractures, steam. The single-phase assumptions that underpin most conventional well-control thinking do not hold here.

This is not such a bad problem for the oil-and-gas people, since it means that they do not have to start from scratch in figuring out how to do geothermal exploration and development. They can take a lot of their hard-earned knowledge about drilling, completions, well integrity, and operational risk management and apply it directly to the problem, to the extent that the comparison is valid. The issue here is that the comparison is not always valid. Some approaches map straightforwardly, while others can be downright dangerous if applied without care.

For engineers moving between the two sectors, the most useful approach is neither uncritical enthusiasm about geothermal potential nor rigid loyalty to conventional methods. It is being honest about where the physics actually differs and adjusting design criteria, well-control envelopes, and operating procedures accordingly.

A geothermal drilling team will recognize much of the rig equipment and many of the workflows used in conventional oil and gas. Rotary steerable systems, measurement-while-drilling (MWD) tools, polycrystalline diamond compact (PDC) bits, managed-pressure drilling (MPD) systems, and real-time data platforms are all in active use in geothermal projects. Yet the equipment must operate reliably in a more severe thermal and mechanical environment.

Downhole tools, elastomers, electronics, drilling fluids, cement systems, valves, seals, and measurement tools may all face temperature limits that are routinely exceeded in geothermal wells but less critical in many conventional operations. The U.S. Department of Energy's Geothermal Technologies Office (DOE GTO) has identified high-temperature bottomhole assembly (BHA) reliability as one of the primary barriers to cost-effective geothermal drilling, noting that drilling can account for more than 50% of total geothermal project cost (DOE GTO, 2024).

The challenge is not only surviving high temperatures. It is also managing temperature change. A well that is cooled rapidly during drilling, circulation, shut-in, intervention, or control operations can experience thermal stress in casing, cement, wellheads, and connections. Temperature and cooling rate should therefore be treated as operational integrity variables, not merely as fluid properties to record.

In practical terms, this means that a geothermal drilling program should treat thermal limits with the same seriousness that a conventional program treats pore-pressure and fracture-gradient limits. Tool selection, elastomer ratings, cement design, connection makeup, and contingency procedures all need an explicit temperature envelope, including the expected range during both continuous circulation and shut-in recovery.

There is a tendency in both industries to reduce well behavior to pressure-volume relationships. That works up to a point, then it breaks. Real gas does not follow a simple PV relationship. It depends on temperature, composition, and compressibility captured by the Z-factor in:

PV = nZRT

where Z is the compressibility factor, n is the number of moles, R is the universal gas constant, and T is absolute temperature. Even in conventional oil-and-gas operations, temperature is never truly irrelevant. Anyone who has managed a gas kick in an HPHT well, or tried to optimize a gas-lift system, knows that pressure and temperature are coupled. The purely isothermal model is a simplification we are willing to make because it is good enough. Geothermal claims no such tolerance.

The fundamental difference in geothermal wells is that the working fluid is not confined to a single phase: hot water flashes to steam and may re-condense back to liquid in response to dynamic pressure and temperature changes along the wellbore. This is a multivariable thermodynamic process governed by the steam tables and liquid-vapor phase equilibrium rather than simple gas expansion laws. When water flashes to steam, its specific volume increases dramatically (over 1,600 times at atmospheric conditions), driving rapid fluid acceleration, gas expansion, and sharp surface pressure variations.

These effects may be unintuitive when interpreted solely through conventional single-phase or gas-flow models. They should therefore be evaluated using rigorous two-phase-flow and steam-water thermodynamic methods.

Table 1 Key physical contrasts between conventional oil-and-gas and geothermal wells. Sources: DOE HGEO (2024); Finger and Blankenship (2010).

In a two-phase geothermal system, lowering pressure may not simply make the well safer. If hot water approaches or reaches saturation conditions, a pressure decrease can cause additional steam formation. Steam occupies approximately 1,600 times the volume of an equivalent mass of liquid water at atmospheric conditions. Even at elevated wellbore pressures, the volumetric expansion is substantial.

The practical lesson is straightforward: pressure reduction must be evaluated together with phase response. An operation that reduces wellhead pressure may still produce a more energetic two-phase flow condition downhole or at the surface. This is the opposite of typical oil-and-gas intuition, where reducing wellhead pressure generally reduces flow energy.

It means it cannot be taken generally and safely for granted. Before any of this happens, the team needs to establish what phase state the fluid will be in at a given depth in the well, whether a pressure drop will push conditions below the saturation curve, and whether the surface equipment, including separators, mud-gas separators, and blooie lines, can handle a sudden increase in the steam fraction that would result. These are serious questions that need to be answered before anyone touches the choke.

Every well has a pressure problem. A geothermal well has the additional challenge of a temperature problem that is just as likely to cause a failure. The downhole equipment and casing are subjected to rapid cooling by cold injection fluid, long-term shut-ins for recovery, or a well-control kill. This type of cooling creates enormous stress on the casing, cement sheath, wellhead, and connections. Metals contract when cooled, causing distortion, and the integrity of the system is compromised. The cement sheath, which has seen several cycles over the producing life of the well, has less tolerance for the additional stresses that might have been acceptable when the well was initially placed on production.

A well that appears to be within pressure limits may also have serious temperature-related problems that shorten its useful life. A technically sound geothermal operational plan should therefore define more than allowable pump pressure and formation fracture constraints. It also needs to pin down:

• Injection-fluid temperature and maximum allowable temperature differential (ΔT)
• Maximum cooling rate (°C/hr) and expected thermal exposure duration
• Casing, wellhead, elastomer, and cement temperature de-rating limitations
• Stabilization and warm-up procedures after the operation

The Geysers geothermal field in California, being the largest producing geothermal complex in the world with installed capacity of approximately 725 MW, has faced a number of problems associated with wellbore shearing, casing damage, and cement degradation due to thermal cycling during injection operations (Majer et al., 2007).

As far as well integrity in geothermal operations is concerned, pressure, temperature, and the general mechanical condition of the well should all be considered together. While keeping a casing string within its pressure ratings is important, multiple quenching and heating cycles may open gaps in the cement sheath, deteriorate bonds, and overload connections. A pressure monitoring program alone will not capture the full integrity picture.

Lost circulation in geothermal drilling is a different animal from what oil-and-gas teams typically encounter. Oil-and-gas drilling experience losses from time to time, perhaps in a troublesome zone, a weakly consolidated formation, or from a drilling parameter that got away from them. In geothermal, losses into highly fractured igneous or volcanic rock are often expected as the norm. The fracture networks are extensive and highly conductive, and no mud weight design is going to give you a stable, continuous fluid column the way you would expect in a matrix-porosity reservoir. Fluid goes into the formation, frequently and in quantity.

Injectivity should be scrutinized as much as losses. A sudden jump in the well's ability to take fluid is not automatically a sign that something productive has been reached. It might be the result of thermal fracturing around the wellbore, loss of a cement sheath seal, or fluid migrating behind casing rather than into the intended interval. The important question is not whether the well can take fluid, but why its injectivity characteristic has changed.

The methods carried over from oil-and-gas practice, including LCM treatments, squeeze cementing, managed-pressure approaches, and rigorous PVT tracking, are all applicable and worth using. What shifts is the interpretation threshold. Severe losses in geothermal are not a red flag that something went wrong; they are often what was planned for. The red flag is when injectivity changes in a way that was not expected, because that is when the well is signaling a change in its mechanical or hydraulic condition.

The Driller's Method is appropriate for wells where circulation is established, which in geothermal cases is often far from the truth. Large losses mean that a Wait-and-Weight kill fluid column will frequently not display the expected density behavior, circulation patterns become unpredictable, and shifts in steam fraction can make surface pressure readings misleading about what is actually happening downhole. This renders many standard well-control procedures inappropriate if applied mechanically without regard to the underlying physics. Not that such procedures should be discarded. Rather, it is essential to recognize the conditions under which they were developed, conditions that often rely on simplifying assumptions that do not hold in a geothermal well.

Instead, the kill strategy should be selected based on what is actually known about the well: whether circulating pressure was intermittent or stable, to what extent temperature-driven density variation dominated the pressure profile, what two-phase flow effects needed to be accounted for at multiple points in the system, and how temperature measurements can be used alongside pressure data to get a reliable picture of downhole conditions. Equally important is defining clear operating windows within which cold injection can be safely continued before unacceptable thermal stress accumulates. Finally, specific criteria must be established for abandoning conventional kill methods and switching to bullheading or capping if the former are no longer viable. All of this must be decided during planning and cannot be left to the pressures of the moment.

The oil-and-gas industry brings essential capabilities to geothermal: advanced drilling practices, high-temperature directional drilling, managed-pressure concepts, cementing and zonal-isolation knowledge, real-time data systems, well-integrity management, and operational risk discipline.

The U.S. Department of Energy's geothermal research programs have funded initiatives targeting improved drilling rates, advanced bits, and high-temperature downhole sensors (DOE GTO, 2024). These programs directly target the two gaps that have historically constrained geothermal economics: the scarcity of reliable downhole tools rated above 175°C, and the absence of purpose-built well-control procedures for two-phase fluid behavior in high-permeability fractured formations.

Recent funding opportunities from the DOE for next-generation geothermal field-scale demonstrations and exploration drilling further signal that the technology-transfer window between oil-and-gas and geothermal is actively expanding.

For students, young professionals, and practicing engineers across the energy community, this represents a major technical career pathway. Skills already developed in HPHT wells, MPD, cement evaluation, real-time operations centers, and well-integrity management map directly onto geothermal needs, provided they are paired with steam-table literacy, thermal-stress awareness, and a willingness to revise well-control intuition where phase behavior demands it (Project InnerSpace and SPE, 2024).

Table 2 Selected oil-and-gas capabilities and their geothermal applications. Sources: DOE HGEO (2024); Finger and Blankenship (2010); Project InnerSpace/SPE (2024).

Geothermal well control is not conventional well control at a higher temperature. It is a coupled pressure-temperature-phase-behavior-integrity problem requiring its own design logic rather than a direct import of oil-and-gas practice. The oil-and-gas community has the skills geothermal development needs. What it also needs is engineers willing to treat the physics honestly rather than assuming prior experience covers the gaps it does not.

The practical rule is simple enough: in a geothermal well, pressure data without temperature context is an incomplete picture, and conventional well-control instincts applied without understanding phase behavior can make a situation worse. The equipment transfers. The discipline transfers. The assumptions need to be checked at the door.

1. U.S. Department of Energy, Hydrocarbons and Geothermal Energy Office (HGEO). Geothermal Drilling Research. Available at: https://www.energy.gov/hgeo/geothermal/geothermal-drilling-research (accessed August 2026).

2. U.S. Department of Energy. DOE Announces $171.5 Million to Help Expand U.S. Geothermal Energy. February 25, 2026. Available at: https://www.energy.gov/articles/energy-department-announces-1715-million-expand-us-geothermal-energy

3. Finger, J. and Blankenship, D. Handbook of Best Practices for Geothermal Drilling. Sandia National Laboratories, SAND2010-6048, 2010.

4. Majer, E., Baria, R., Stark, M., et al. "Induced Seismicity Associated with Enhanced Geothermal Systems." Geothermics, Vol. 36, No. 3, pp. 185–222, 2007.

5. Project InnerSpace and SPE. Project InnerSpace and SPE Partner to Strengthen Technical Focus on Geothermal. ThinkGeoEnergy, 2024. Available at: https://www.thinkgeoenergy.com/project-innerspace-and-spe-partner-to-strengthen-technical-focus-on-geothermal/

6. SPE Journal of Petroleum Technology. Geothermal Energy 2026. Available at: https://jpt.spe.org/geothermal-energy-2026

7. International Energy Agency (IEA). Geothermal Power: Technology Brief. IEA, Paris, 2023.

I was born in Dhaka, Bangladesh—a young nation marked by resilience, yet scarred by wars, political upheavals, and the constant struggle against poverty. My childhood memories were painted in the dim light of kerosene lamps. I can still remember many mothers in Africa carrying their children on their backs as they walk long distances to gather firewood or charcoal, determined to provide for them. I can see myself and my sister bent over our homework, eyes straining under flickering lamps, silently wishing for the luxury of steady electricity. Energy poverty wasn’t just statistics—it was our life. It shaped my sense of resilience, but it also sparked a lifelong question: why should a lack of light dim any child’s dreams?

My father’s United Nations assignments took me to Rwanda, Uganda, and Kenya. Those experiences opened my eyes to the transformative power of access to energy on entire communities. In Kenya, I saw villages once bound to kerosene lamps and smoky kitchens suddenly alive with reliable electricity. Schools could run evening classes, women had time for businesses, and small farms gained new productivity. With nearly half of Kenya’s electricity now generated from geothermal energy, it became clear to me: geothermal is not just about power plants—it is about dignity, freedom, and opportunity.

When I arrived in the United States on a scholarship to Texas A&M University in 1998, I believed I was entering the world’s most advanced energy economy. But driving through Texas, I encountered another truth. Places like Presidio, Texas, stood as reminders that energy poverty doesn’t only belong to developing nations. Despite being part of the richest country in the world, Presidio’s people live with limited jobs, unreliable electricity, and inadequate healthcare. Families often move away just to survive. It struck me deeply—energy poverty wears different faces, but the suffering is the same.

Despite progress in fossil fuel and nuclear energy, Bangladesh’s geothermal promise remains untapped. Regions like Singra–Kuchma and Barapukuria show resource potential exceeding 5 GW, yet a lack of policy frameworks and investment keeps this resource buried. Meanwhile, millions still rely on biomass fuels, which carry all the associated health and environmental consequences. I see the same potential in Bangladesh that I saw in Kenya decades ago—a chance to ignite development through geothermal energy, if only the right roadmap is laid out.

I spent years working in the oil and gas industry. It provided me with financial stability, global travel opportunities, and professional prestige. Yet each layoff—twice in my career—reminded me of the volatility and emptiness of fossil fuels. Oil and gas showed me wealth, but it didn’t feed my soul. Geothermal, however, felt different. It demanded patience, persistence, and perseverance—values I carried from my childhood. But it also promised something more: the power to leave behind a lasting legacy of light and hope.

Kenya: With nearly 1,000 MW of installed capacity, geothermal now accounts for 45–47% of the country's electricity generation. It lowered costs, stabilized the grid, and lifted millions from the shadows of energy poverty. Presidio, Texas: A 110 MW geothermal project is in motion. With the right planning, it can bring jobs, stabilize the electricity supply, and revitalize a struggling community. Bangladesh: With an estimated potential of more than 5 GW, it stands where Kenya once was. Exploration, donor-backed pilots, and policy reforms could spark a new era of energy.

My story is not just about professional shifts—it is about a lifelong pursuit to end energy poverty. From Bangladesh’s flickering lamps to Kenya’s bright classrooms, from Presidio’s empty hospitals to the promise of sustainable geothermal baseload, I have seen both the shadows and the light. For me, geothermal is not just energy. It is freedom from cycles of poverty, resilience in the face of climate change, and hope for communities too often left behind. Kenya has proven what is possible. Presidio can show it is possible here in America. Bangladesh can begin its journey. As for me, I carry the same commitment that lit my path from Dhaka to Texas: to never give up on geothermal’s promise—to light the way for millions still waiting in the dark.

Now is the time for oil and gas to look down at the great opportunity before them—to do what is right for their employees, customers, shareholders, the environment, and future generations. We’ll explain why oil and gas companies should invest in geothermal energy.

• Pressure is mounting for the oil and gas industry to become carbon neutral, and that pressure will only increase in the coming decades. Geothermal energy is carbon neutral.
• Oil and gas companies have explored the subsurface of the earth for decades. People in the oil and gas companies are seeking cleaner, greener jobs. Their technology, expertise, and data collection bring unique advantages to the geothermal space and help decrease costs. Investing in geothermal energy is a natural pivot for oil and gas companies that will make their employees and shareholders happy.
• Hot water, which geothermal energy produces, will become increasingly valuable to the oil and gas industry.
• Both industries have similar technologies, knowledge, and expertise.
• Both industries find and engineer reservoirs under the earth’s surface.
• Old oil and gas wells can be repurposed to become geothermal heat sources.

More and more  oil and gas firms are committing to achieve net-zero emissions by 2050. Why is it important for this industry to become carbon neutral? According to McKinsey, oil and gas production contributes 42% of the global greenhouse gas emissions. That’s a lot of CO2.

Why is reducing CO2 emissions important? According to NOAA, despite the global pandemic, carbon dioxide levels are higher than any time in the last 3.6 million years. If oil and gas companies don’t get on board to be carbon neutral, we won’t solve the CO2 problem.

In February 2020, BP announced net-zero carbon emissions by 2050 or sooner. And other oil and gas companies have also said they plan to become carbon neutral or significantly reduce their carbon footprint including Paris-based Total, the Netherland’s Royal Dutch Shell, ExxonMobil, Chevron, the Spanish oil and gas company Repsol, and PetroChina.

But with rising CO2 emissions, the current scenario demands immediate action. A partnership with geothermal companies can help oil and gas companies become more carbon neutral by repurposing old oil and gas wells. Using geothermal energy equipment in abandoned or unproductive oil and gas wells helps address the need for more renewable energy sources.

As the oil and gas industry continues to decline, workers are looking for new job opportunities. Because many of the drilling technologies and methods are similar, workers can easily transition to geothermal energy jobs and help create clean energy. Solar, wind, hydro, and nuclear power require very different technologies. Geothermal is a great fit for former oil and gas workers. In fact, some of the folks working on developing new geothermal technologies are senior executives from the oil and gas industry. Simply put, geothermal energy provides the opportunity for oil and gas companies to leverage what they already know and do to generate renewable energy.

And, there are plenty of wells already in production. According to the U.S. Energy Information Administration, there are 483,326 gas producing wells that are active in the United States, and it’s forecasted that 22,600 new wells will be created in 2022. The U.S. Environmental Protection Agency estimates that there are more than 3 million total abandoned oil and gas wells. Why don’t we use these wells to create clean energy and new green jobs for workers?

Over the next decade, society will need a mix of renewable energy and clean energy. We will especially need energies that are always on, regardless of the time of day or the weather. There are significant opportunities for collaboration across industries as we work together to solve the energy crisis.

Oil and gas companies have a huge opportunity to not only survive the transition to clean energy, but also thrive as renewable energy leaders, if they invest in geothermal energy now.

The next step for oil and gas leaders is to collaborate with Geothermal Rising and the geothermal industry. While there are many similarities with supplying oil and gas and supplying geothermal energy, geothermal experts have decades of knowledge on key differences and can help your company come out of the energy transition a winner.

https://www.nsenergybusiness.com/news/why-the-oil-and-gas-industry-should-expand-into-geothermal-energy/

https://energytracker.asia/oil-and-gas-industrys-net-zero-commitments/

https://research.noaa.gov/article/ArtMID/587/ArticleID/2742/Despite-pandemic-shutdowns-carbon-dioxide-and-methane-surged-in-2020

https://insideclimatenews.org/news/29072021/inside-clean-energy-geothermal-energy-oil-workers/

https://www.eia.gov/dnav/ng/ng_prod_wells_s1_a.htm