Deep geothermal is not oil and gas. The wells still are.

You have a licence, a customer for the heat and a funding round that depends on two wells coming in on time and on budget. The energy is renewable and the business model is new, so it is tempting to assume deep geothermal drilling is new too. It is not. A deep geothermal well is a hole several kilometres into rock you know mainly from seismic surveys, lined with steel and cement that must hold hot, pressurised water for decades. That is an oilfield problem, and the wells are usually the largest single line in your capital budget.

Why is deep geothermal drilling an oil and gas problem?

Take away the product and the two industries do the same thing at depth. They drill through rock that rarely behaves exactly like the model, manage pressure so fluids stay where they belong, and set steel casing and cement to seal the well off from every layer it crosses. The failures are shared too: drilling fluid lost into fractured rock, stuck pipe, cement that does not bond, a well that leaks behind the steel years after the rig has gone. Each shows up in your budget as extra rig days or, worse, a well that has to be repaired.

The geothermal well often has the harder brief. It runs hot for its whole life, heats and cools every time it is started and stopped, and produces brine that can carry gases and minerals that attack steel and cement. And the business case assumes the pair of wells, one bringing hot water up and one sending it back down, will run for decades.

What can geothermal well engineering borrow from oil and gas?

Oil and gas learned its well discipline through expensive incidents and wrote the lessons into how wells are delivered. Four parts carry over to geothermal almost unchanged:

• Two seals at all times. Wherever the well can flow, at every stage of its life, there are two independent, tested barriers between the hot water underground and the surface, and everyone on the rig knows what they are. If one fails, the other holds, so a fault stays a repair job instead of becoming an incident or a headline. Geothermal wells need this through every shutdown and restart, when temperatures swing.
• A second pair of eyes. Someone who did not design the well reviews the design, and later the well as built, against a written standard. It catches what the design team can no longer see, while a fix still means changing a drawing, not paying for rig days.
• Limits set before the rig arrives. The design assumptions are written down, operating limits are agreed in advance, and any change is reviewed, not improvised at three in the morning. You see what a change costs before it is made, not on the invoice.
• Crews that perform the same on every shift. Procedures, drills and handovers that keep performance repeatable across shifts and contractors, not dependent on one experienced driller.

This is how we approach drilling and well engineering across the well lifecycle, from the first design assumptions to supervision at the rig. For geothermal, the work is translation: keep the principles, change the numbers, and design for heat cycles and corrosive brine that a standard written for hydrocarbons may not anticipate.

Why does geothermal regulation slow deep wells down?

In many countries deep geothermal sits under a mining or petroleum law, a water law, or a patchwork of local permits; in Switzerland it is handled canton by canton. Developers usually meet one of two situations, and both cost time.

• The rules assume an oil or gas well. Hydrocarbon requirements are applied to a hot-water well. Some fit, some miss what matters for heat, such as decades of thermal cycling, and the developer ends up arguing clause by clause.
• The rules are thin or silent. The regulator has little to measure the well against, so every submission raises new questions and approval stalls while the rig schedule slips.

In both cases, start from the well standards that oil and gas regulators already recognise (NORSOK, ISO and API), state plainly where a geothermal well departs from them and why, and agree that position with the regulator before the design is frozen. That is the heart of our regulatory support for geothermal developers, and you can see it applied in the engagement we publish as Deep geothermal wells, delivered to standard.

Read the file the way the authority will: before it can say yes, a regulator needs a subsurface case it can follow, risks stated plainly, and a well plan that shows what happens when the ground does not match the model. Leave one out and expect another round of questions.

Which deep geothermal project risks should you price before FID?

Most developers are well briefed on resource risk: the rock may be cooler or less permeable than hoped. The surprises tend to sit in the well and around it.

• Trouble time. Days when the rig is paid but not drilling ahead, because fluid is disappearing into fractured rock or the pipe is stuck. Rigs are hired by the day, so a slow week is a budget problem, not a technical footnote.
• Geothermal well integrity over decades. Cement and casing that pass inspection on completion day can crack or corrode after years of heat cycles and aggressive brine. Replacing a well is effectively a second capital project.
• Induced seismicity. Injecting water into deep, stressed rock can trigger small earthquakes, and tremors felt at the surface have halted deep geothermal projects in Europe. Knowing where the faults are and how the rock is stressed is a geosciences evaluation question for before the first well is sited, not after.
• Contractor fit. A contractor with a good record on shallow heat wells may lack the systems for a deep, hot, pressured one. Ask how they control pressure in the hole, verify barriers and train crews, and ask for evidence.

Pricing these risks means three things before FID: a realistic allowance for trouble time in the schedule and contingency, a drilling contract that says who pays when the hole misbehaves, and a well design that states how long it is meant to last in heat and brine. If any of the three is missing, the budget you take to the board is a best case, not a forecast.

When should a developer bring in an owner's engineer?

Earlier than most do. The cheapest place to change a well is on paper: before the design is frozen, the drilling contract signed or a submission sent to the regulator. At that stage an owner's engineer can challenge the design assumptions, write the operating limits into the contract and prepare the regulatory case in parallel. Later, the same team belongs at the rig, where the decisions that move the budget are made, often at night.

If you are funding the project rather than running it, the same questions belong in your technical due diligence before you commit: is the well plan realistic, is trouble time in the budget, and will the regulator accept the design?

The contractor is paid to drill and the service companies to supply. Someone with oilfield experience has to sit on the developer's side of the table and ask whether the well being drilled is the well that was designed and approved. That is the role we have played as owner's engineer across oil and gas, geothermal and CO2 storage since 2015.

Whether your wells are still on paper or the rig is already on site, tell us where the project stands. The partner who scopes the review stays on it through delivery, so the person who read your well plan is the one on the call when the rig is running.