Hundreds of thousands of abandoned and end-of-life oil and gas wells worldwide pose environmental liabilities, including methane leakage and groundwater contamination. At the same time, they represent a unique sub-surface asset: pre-drilled access to warm formations that can be tapped for geothermal heat or, in some cases, low-enthalpy power generation. In practice, only a subset of wells has the right characteristics for economic retrofit. At Energy Solutions, we assess when geothermal retrofits can transform a legacy liability into a transition-aligned infrastructure asset.
Abandoned wells are typically viewed purely as liabilities requiring plug-and-abandonment work to prevent fluid migration. However, they already provide expensive access to subsurface formations, which can represent several million USD of sunk drilling cost per well. Retrofitting such wells for geothermal use can, in principle, capture some of that sunk value.
In practice, the opportunity is highly site-specific. Key questions include:
Where these conditions are satisfied, a geothermal retrofit can turn a dormant or abandoned asset into a source of low-carbon heat for decades.
This report analyzes the 2027 market potential for retrofitting abandoned oil wells into geothermal assets, with emphasis on CAPEX reduction versus greenfield drilling and the technical feasibility constraints that determine bankable projects.
In practice, the opportunity is highly site-specific. Key questions include:
Screening typically eliminates the majority of wells. A practical planning assumption is that roughly 10–25% of abandoned wells are viable candidates for geothermal retrofitting, depending on integrity, depth, thermal gradient, and proximity to end-users.
The chart below shows a stylised geothermal gradient and bottom-hole temperatures for wells of different depths in regions with moderate to favourable conditions.
Not every abandoned well is a candidate for geothermal reuse. Operators typically apply a screening funnel:
| Parameter | High-Priority Candidate | Marginal Candidate | Unfavourable |
|---|---|---|---|
| Well Depth | 2.5–4.0 km | 1.8–2.5 km | <1.5 km |
| Temperature Gradient | 35–45 °C/km | 25–35 °C/km | <25 °C/km |
| Casing Integrity | Good logs, few repairs | Moderate repairs needed | Major integrity issues |
| Heat Demand Distance | <5 km | 5–15 km | >20 km |
Retrofitting an existing well avoids the full drilling cost of a new geothermal well, but still requires significant investment in workovers and surface systems.
| Project Type | Capacity (Thermal) | CAPEX Range | Indicative Metric |
|---|---|---|---|
| New Geothermal Doublet (Greenfield) | 5–15 MWth | 25–60 million USD | 2,500–4,500 USD/kWth |
| Retrofit of Abandoned Well (Single) | 1–3 MWth | 3–7 million USD | 2,000–3,500 USD/kWth |
| Cluster Retrofit (3–5 Wells) | 6–15 MWth | 12–35 million USD | 1,200–2,800 USD/kWth |
Values exclude the cost of connecting to long-distance district heating networks; they assume local heat demand within 5–10 km of the wells. All numbers are indicative and vary markedly by country, drilling market and subsurface conditions.
The chart below compares stylised LCOH ranges for three options under 2027 market conditions.
A unique feature of abandoned-well retrofits is the interaction between geothermal project economics and avoided plug-and-abandonment costs. If an operator would otherwise spend 1.2–2.0 million USD on P&A, that liability can be partially re-purposed as equity in a geothermal SPV.
For example, consider a 2 MWth retrofit project supplying process heat to a nearby industrial facility:
If this heat displaces a 90%-efficient gas boiler with fuel costs of 7–10 USD/MMBtu and a carbon price of 50–100 USD/tCO₂, the retrofit can yield abatement costs around 20–60 USD/tCO₂ with positive project IRRs in the 8–14% range.
In a mature onshore basin, a refinery and three neighbouring industrial plants sit within 8 km of a group of abandoned oil wells previously producing from a 3 km-deep reservoir.
The resulting LCOH is estimated at 20–28 USD/MWhth. With gas boiler costs effectively at 35–55 USD/MWhth including carbon, payback periods of 7–10 years are achievable under conservative assumptions.
A small town near a legacy oilfield in a cold climate region develops a district heating loop supplied by three retrofitted wells.
While the full network CAPEX pushes LCOH into the 35–45 USD/MWhth range, the project sharply reduces imported fuel dependency and delivers annual CO₂ savings of 12–18 ktCO₂. It also preserves local employment for drilling and service crews in a declining oilfield.
The line chart below shows how project IRR responds to different assumed gas prices, holding CAPEX and carbon price within indicative 2027 ranges.
Geothermal retrofits sit at the intersection of upstream O&G and district heating infrastructure. Key supply chain elements include:
While the narrative of “turning liabilities into assets” is attractive, several risks warrant caution.
These factors argue for a disciplined screening process and transparent risk-sharing between upstream owners, heat offtakers and public entities when strategic infrastructure benefits are involved.
By 2035, geothermal retrofits are unlikely to represent a dominant share of global heat supply, but they can form a meaningful niche in regions with suitable geology and concentrated heat loads. In upstream portfolios, they offer:
For O&G companies and municipalities exploring this space, a structured approach is essential.
Assess Your Well's Geothermal Potential: Email contact@energy-solutions.co with depth, temperature logs, integrity results, and distance to the nearest heat offtaker.
Only a small fraction of abandoned wells meet the depth, temperature, integrity and proximity-to-demand criteria required for economic retrofit. Energy Solutions analysis suggests that in many basins, 10–25% of wells may be viable candidates for geothermal retrofitting after integrity and location filtering. The exact share depends strongly on local geology and infrastructure.
Most retrofit opportunities are better suited to direct heat due to moderate bottom-hole temperatures. Binary-cycle power generation requires higher temperatures and adds complexity and cost. In many cases, using the resource purely for heat delivers lower LCOH and higher overall system efficiency than forcing power generation at marginal temperatures.
Efficiency and geothermal are complementary. Deep efficiency retrofits can reduce heat demand by 30–50%, lowering the required size and cost of geothermal systems. In some markets, the lowest-cost sequence is efficiency first, then geothermal for remaining loads. In others, especially where building stock is newer, geothermal retrofits of wells may compete directly with gas boiler upgrades on abatement cost.
Ownership models vary. Some projects are led by O&G companies repurposing their own wells; others involve specialised geothermal developers purchasing or leasing well access, often in partnership with municipalities or utilities. Clear long-term allocation of well integrity and decommissioning responsibilities is essential regardless of model.
Regulators must be satisfied that reopening or repurposing wells will not increase risks to groundwater or surface environments. Permitting frameworks originally designed for hydrocarbon production or decommissioning may not explicitly cover geothermal reuse, creating uncertainty. Successful projects often involve early engagement with regulators and, in some cases, pilot or sandbox frameworks to test new approaches.
Avoided P&A costs can be significant. Where baselines involve spending 1–3 million USD per well on decommissioning, allocating part of that amount into a geothermal SPV can materially improve IRR and reduce required third-party funding. However, operators and regulators must still ensure that eventual decommissioning is fully planned and funded when the geothermal asset reaches end of life.
Well-designed projects can provide stable, local heat supply, support decarbonization targets and preserve jobs for drilling and service crews. However, poor communication or unclear responsibility for long-term integrity can undermine trust. Transparent engagement on risk allocation, tariffs and environmental safeguards is therefore critical for community acceptance.
For a brownfield retrofit with existing wells, realistic timelines from concept to commissioning are typically 3–6 years. Subsurface assessment and FEED may take 12–24 months, permitting another 12–24 months, and construction plus commissioning 12–24 months depending on heat network complexity. Projects aligned with existing industrial clusters can move faster than new district heating schemes starting from scratch.