Decommissioned open-pit mines are potential geothermal sources of heating or cooling for nearby population centres

Coal still supplied about one-third of global energy demand in 2021, but to meet climate targets all unabated coal power plants must close or be repurposed by 2040. As coal demand falls, many open-pit coal mines will be decommissioned worldwide. Traditional decommissioning focuses on stability and risk reduction, often creating pit lakes through rapid flooding, with end uses mainly in conservation and recreation. There is a need to identify additional post-mining uses that support socio-economic transitions of nearby communities. Shallow (low-enthalpy) geothermal energy systems can potentially leverage pit lakes or mine water as heat sources/sinks, using heat pumps for space heating and cooling, and can integrate with mine closure solutions without major modifications. However, geothermal reuse of open pits is rare due to distance from population centres, limited awareness in the mining sector, and lack of guidance on low-temperature energy transport over longer distances. This study aims to evaluate the techno-economic feasibility of supplying heating and cooling from decommissioned open-pit mines to nearby residential areas, providing conditions under which such systems can be competitive.

Existing databases identified 20 mining-related shallow geothermal projects in 2014, expanded to 45 by 2021, with only two documented cases of pit lake geothermal reuse. Most mining geothermal projects reuse abandoned mine workings; underground coal mines are often closer to dense populations and present natural reservoirs, while open pits are typically distant, complicating heat transport. Prior work highlights the importance of proximity to large water bodies for district-scale heat pumps but lacks distance cut-offs. Excess heat literature suggests transmission can be economic below about 0.5 EUR GJ−1 up to 50 km (based on Danish experience), but no studies were found on long-distance, low-temperature heating and cooling from pits. Overall, there is a gap in detailed techno-economic analyses for transporting low-temperature geothermal energy from decommissioned open pits to end users.

Two case study regions were analysed where large open-pit coal mines will be decommissioned: the Latrobe Valley (Victoria, Australia) and the Rhenish Coal Mining Area (North-Rhine Westphalia, Germany). Residential thermal demand was represented by clusters of single-family houses (SFHs). Weather forcing used Typical Meteorological Year (TMY) data. Hourly heating and cooling loads were computed with the EN-ISO 13790 5R1C simplified method, parameterised for representative SFHs in each region. Two network configurations were modelled: (1) Decentralised (ambient temperature network), where mine water exchanges heat via a central heat exchanger to a non-insulated twin PE transmission pipeline supplying consumers; each dwelling uses a reversible water-source heat pump for heating/cooling. (2) Centralised (4th Generation District Heating), where mine water feeds a central heat pump that supplies heating via heat interface units; cooling is met by individual reversible cycle air conditioners (RCAC). A benchmark individual supply case includes RCAC (cooling and possibly heating) and a gas boiler for heating. Electricity tariffs differ by component type (industrial/commercial for shared plant; residential for household devices). The transmission/distribution among consumers was not modelled; only the mine-to-cluster transmission was included. Investment, O&M, and commodity costs were annualised using equivalent annual cost; LCOE was defined as EAC divided by total annual thermal demand. A normalised competitiveness metric LCOEnorm was defined as the ratio of individual-source LCOE to thermal system LCOE. Base cases assumed a 10 °C source temperature, non-insulated PE transmission pipes, and region-specific electricity and gas prices. Sensitivity analyses varied source temperature, pipe insulation, and electricity price across transmission lengths and cluster sizes. Operational optimisation used the COMANDO framework with a mixed-integer quadratically constrained programming (MIQCP) formulation to capture mass/energy balances, heat losses, and HP performance. Time series aggregation applied K-medoids typical days (12 typical days plus 2 design days for peak heating/cooling). The GUROBI solver (v10.0) targeted a 0.01 MIP gap. Ground–pipe thermal interactions used undisturbed ground temperature profiles derived from air temperature via a frequency-domain approach, and steady-state hydraulics/heat transfer were assumed for the transmission. Component costs and lifetimes were compiled from European/German/Danish sources and adjusted to June 2022 German price levels; the same capital cost data were used for Australia to enable comparison; commodity prices reflected German and Victorian data. Modelled components included sources (mine thermal source, grid electricity and gas), sinks (heating and cooling demands), and transformers (pipes with pumping and heat losses/gains, heat exchangers, heat pumps, RCACs, boilers). HX and HIU were sized for investment cost but not explicitly controlled in optimisation to reduce complexity.

• LCOE vs Q/L: For both regions and configurations, LCOE decreases rapidly with increasing total annual demand per unit transmission length (Q/L) up to around 1 MWh m−1, after which it declines more slowly and then largely stabilises near 10 MWh m−1, indicating diminishing influence of transmission CAPEX beyond this inflection.
• Centralised vs decentralised performance depends on region: In NRW, the centralised case achieved lower LCOE than the decentralised case, driven by economies of scale in HP CAPEX and a favourable industrial-to-residential electricity price ratio (~0.56). In VIC, the decentralised case outperformed the centralised case due to a smaller tariff differential (~0.81) and high RCAC cooling requirements and lower efficiency in the centralised configuration.
• Source temperature effect: Higher mine-water source temperatures reduce LCOE, especially in heating-dominated systems. Benefits are more pronounced at higher Q/L. In decentralised VIC, LCOE curves converge for Tsource ~40–50 °C at larger Q/L due to warmer ground temperatures reducing relative heat losses; NRW remains more sensitive due to cooler ground.
• Insulation impact: Transmission pipe insulation provided limited economic benefit overall. In VIC, insulation was generally negligible or detrimental to LCOE. In NRW, selective benefits occurred for shorter transmission lengths (≤1000 m) at higher Tsource (>30 °C), but at long lengths (5–10 km) added investment costs offset commodity savings. Non-insulated PE pipes’ smoother surfaces allow higher mass flow than insulated steel pipes of equal diameter, influencing optimal design.
• Long-distance/centralised limits at high Tsource: For centralised cases at long transmission lengths (5–10 km), high Tsource yielded little LCOE benefit at low Q/L because increased mass flow to curb heat losses caused large pumping penalties; the solver found no net benefit.
• Electricity price sensitivity: For fixed Tsource, LCOE increased roughly 25–40 EUR MWh−1 per 0.1 EUR kWh−1 rise in electricity price. Economic competitiveness relative to individual systems exhibits a hinge around ~0.3 EUR kWh−1 consumer electricity price, where the optimal individual solution shifts from RCAC-only to gas boiler plus RCAC.
• Competitiveness trends: Higher Q/L and higher Tsource improve competitiveness. At Tsource=10 °C, VIC decentralised cases were generally not competitive; NRW had some competitive configurations for Q/L > ~10 MWh m−1. Centralised systems showed smaller gains with increasing Tsource and greater variance at Tsource=50 °C due to fixed evaporator ΔT assumptions reducing COP.
• Planning insight: Larger consumer bases (higher Q/L) can make longer transmissions viable; economic outcomes are highly sensitive to electricity tariffs, local cooling/heating demand balance, and achievable source temperature. Benefits of pipe insulation are case-specific.

The study demonstrates that decommissioned open-pit mines and associated pit lakes can serve as viable low-enthalpy geothermal sources or sinks for nearby residential heating and cooling under specific techno-economic conditions. By explicitly modelling thermal hydraulics, heat pump performance, and costs, the analysis clarifies key determinants of feasibility: the ratio of thermal demand to transmission length (Q/L), electricity pricing structures (especially industrial vs residential tariffs), the mine-water source temperature, and local cooling demand. The centralised vs decentralised choice is context-dependent: where industrial electricity is substantially cheaper and cooling demand is low (NRW), centralised plants can outperform; where tariff differentials are modest and cooling loads are higher (VIC), decentralised ambient networks with consumer heat pumps can be superior. Findings address the initial hypothesis that distance and lack of guidance impede adoption by identifying thresholds (e.g., Q/L ≈ 1 MWh m−1 inflection) and illustrating when longer transmission can remain competitive. Limited average benefits from transmission insulation reflect trade-offs between reduced losses and higher CAPEX and pumping; thus, insulation should be evaluated site-by-site, particularly when the temperature source is valuable or constrained. Overall, the results are relevant for mine closure planning, providing quantitative guidance to prioritise sites and configurations that foster socio-economic transition via low-emission thermal services.

This first-of-its-kind techno-economic assessment for reusing decommissioned open-pit mines as shallow geothermal sources identifies general conditions for competitiveness. Thermal systems become more cost-effective as Q/L increases, with an LCOE inflection observed near 1 MWh m−1 for the analysed cases. Higher source temperatures reduce costs, particularly with larger consumer bases, while transmission insulation offers limited or case-dependent benefits due to added investment and pumping trade-offs. Economic competitiveness relative to individual supply options hinges on electricity tariffs (notably a ~0.3 EUR kWh−1 hinge where individual systems switch from RCAC-only to gas+RCAC) and local heating/cooling profiles. The study suggests that centralised configurations can excel where industrial electricity tariffs are significantly lower and cooling demand is small, while decentralised ambient networks may be preferable otherwise. Although subsidies or carbon-related incentives were not considered, their inclusion would likely enhance competitiveness. Future research should model dynamic source temperatures and availability across closure phases, include distribution and source exploitation costs, investigate optimal mine–lake heat exchange designs, and incorporate prosumer demand balancing and more detailed transient hydraulics and thermal dynamics.

Key limitations include: assuming a constant temperature source and fixed commodity prices; steady-state transmission hydraulics and ground–pipe heat transfer; exclusion of consumer-side distribution network costs and source exploitation costs; simplified treatment of centralised HX and HIU (sized for CAPEX but not explicitly controlled); no demand balancing among prosumers in ambient networks; and omission of subsidies, decarbonisation incentives, or penalties. Results are based on representative SFHs and equalised component costs across regions to facilitate comparison, so extrapolation should be done case-by-case with local data.