Enhanced Geothermal Systems: Reservoir Sizing, Drilling Economics, and Grid Integration

Why deep geothermal is a drilling problem as much as a heat problem

Conventional geothermal power taps naturally permeable, water-saturated hot rock near the surface — it only works where geology cooperates, which is why historically it has been limited to volcanically active regions like Iceland, the western United States, and parts of Indonesia. Enhanced Geothermal Systems (EGS) remove that geographic constraint by drilling into hot but impermeable rock at depth (typically 3-5 km, where temperatures exceed 150-200°C in favourable continental crust), then hydraulically fracturing an artificial reservoir and circulating water through it to extract heat. Because EGS works anywhere the crust is hot enough at reachable depth, it is often described as the technology that could make geothermal a viable baseload source far beyond today's volcanic hotspots — but the economics are dominated by drilling cost, not the underlying physics of heat extraction.

Estimating reservoir power output

The heat available from a geothermal reservoir depends on the local geothermal temperature gradient (how many degrees Celsius the rock warms per kilometre of depth, typically 25-35°C/km in stable continental crust, though EGS targets are usually chosen for above-average gradients around 40-50°C/km), the mass flow rate of water circulated through the reservoir, and the plant's conversion efficiency from thermal to electrical power.

Thermal power output follows directly from basic calorimetry: mass flow rate × specific heat capacity of water (4.18 kJ/kg·°C) × the temperature difference achieved between injection and production wells. For a gradient of 45°C/km and wells reaching an average depth of roughly 2.5 km, the achievable temperature differential is around 110-115°C; combined with a flow rate of 180 kg/s, thermal power comes out around 85-90 MW thermal. Binary-cycle and Organic Rankine Cycle (ORC) plants — which use a secondary working fluid such as isobutane with a lower boiling point than water, letting the plant extract useful work from moderate-temperature brine — typically convert 10-15% of that thermal energy to electricity, while higher-temperature flash-steam systems can reach closer to 20%. At 42% stated 'plant efficiency' in a simplified model this is optimistic relative to real ORC hardware, but the calculation logic — thermal power × conversion efficiency = net electrical output — holds regardless of which efficiency figure is used, and it's the number project developers use to size the turbine and estimate revenue.

Drilling: the cost driver that makes or breaks EGS economics

Drilling routinely accounts for 40-60% of total EGS project capital cost, which is why drilling time and day-rate assumptions matter more to project viability than almost any other input. Deep geothermal wells use petroleum-industry drilling rigs adapted for higher-temperature, harder crystalline rock, which drills more slowly than the sedimentary formations oil and gas rigs are typically optimized for — a rough industry planning figure is 10-15 drilling days per kilometre of depth for hard crystalline rock, compared to a few days per kilometre in soft sedimentary basins.

For a 3.2 km target depth, 6 wells (a typical arrangement pairs injection and production wells, with 4-8 wells common for a mid-size plant), and a rig day-rate of $68,000: at roughly 12 days/km, each well takes about 38 days, and six wells sequenced on a single rig take roughly 230 days total, giving a drilling CAPEX around $15-16 million — though projects that drill wells in parallel with multiple rigs, or that repurpose depleted oil and gas wells to cut both time and cost, can bring this down substantially. Repurposing existing hydrocarbon wells is an increasingly common cost-reduction strategy, since much of the casing and wellbore work is already in place.

Because a single unsuccessful well (insufficient permeability, unexpected fault offset, wellbore instability) can add tens of millions in cost without adding output, EGS projects increasingly front-load exploratory drilling and fibre-optic distributed temperature sensing to de-risk the full well count before committing to the complete drilling campaign.

Induced seismicity: the operational risk unique to EGS

Because EGS creates its reservoir by hydraulically fracturing rock — deliberately opening and shearing fracture networks to increase permeability — it can trigger induced seismicity, small to moderate earthquakes caused by the injection process itself. This isn't a hypothetical concern: EGS pilot projects in Basel, Switzerland (2006) and Pohang, South Korea (2017) both triggered felt earthquakes strong enough to halt operations, with the Pohang event (magnitude 5.5) linked to a larger earthquake that caused significant damage and led to project cancellation.

Modern EGS projects manage this risk through traffic-light protocols — real-time seismic monitoring networks around the injection site with predefined magnitude thresholds that trigger reduced injection rates (yellow) or complete shutdown (red) — combined with gradual, staged pressure ramp-up rather than rapid full-pressure injection. This monitoring infrastructure is now considered a mandatory, non-optional part of EGS project design in most jurisdictions, not an add-on.

Grid integration: geothermal as flexible baseload

Geothermal's key grid value proposition is that, unlike solar or wind, it produces continuous power regardless of weather or time of day — true baseload generation. But a geothermal plant's steady output rarely matches a grid's peak demand shape on its own. Grid integration analysis compares plant output against system peak demand to calculate peak coverage, and separately sizes battery storage in terms of hours of plant output it can bank and discharge during demand peaks.

For a 65 MW plant against 120 MW peak demand with 180 MWh of storage: peak coverage is 65/120 ≈ 54%, meaning the plant alone covers just over half of peak load, with storage providing 180/65 ≈ 2.8 hours of full-output buffering that can be discharged to help bridge the gap during the highest-demand hours. Below roughly 50% peak coverage, grid planners typically recommend either additional flexible generation (gas peakers, hydro, or additional geothermal wells) or demand-response programs rather than relying on storage alone to close a structural capacity gap.

A growing number of EGS projects also pursue combined heat and power — routing a portion of the extracted heat directly to district heating networks or greenhouse operations rather than converting all of it to electricity, since direct heat use avoids the thermal-to-electric conversion loss entirely and can raise the overall energy utilization of the resource well above what electricity generation alone achieves.