Geothermal energy extraction using existing wellbore systems provides a promising approach for sustainable heat utilization; however, the long-term thermo-hydro-mechanical (THM) responses associated with different working fluids remain insufficiently understood. In this study, a three-dimensional coupled THM model was developed to compare geothermal heat extraction using water and pressurized CO2 under identical geological and operational conditions. The model integrates Darcy flow, heat transfer, and linear elastic deformation to investigate the evolution of hydraulic, thermal, and mechanical fields over a 100-year operation period. The results show that the hydraulic fields rapidly reach quasi-steady states, whereas thermal responses continuously evolve due to cold-front propagation from the injection well. Compared with water, pressurized CO2 exhibits stronger fluid mobility and produces a larger thermal influence region, resulting in different heat extraction characteristics under the same mass-flow-rate condition. Thermal cooling induces reservoir contraction and stress redistribution; however, the calculated stress and displacement variations remain within a stable range throughout the simulation period. The comparison demonstrates that pressurized CO2 can enhance long-term thermal utilization while maintaining acceptable geomechanical stability under the investigated conditions. These findings provide insights into the selection of working fluids for wellbore-based geothermal systems and highlight the importance of coupled THM evaluation for long-term reservoir performance assessment.
Donghuan Han, Yan Xia, Xiang-Yang Wang et al.· Energies· 0 citations
Carbonate gas reservoirs are characterized by strong heterogeneity and a complex combination of pores, fractures, and caves. The productivity of gas wells is controlled by many factors, including geology, development, and engineering factors. The traditional one-point productivity evaluation method is insufficient to accurately characterize the productivity differences in gas wells with different reservoir types. In this paper, the carbonate gas reservoir of the MK Formation in the HS 4 block is taken as the research object. Based on core characteristics, thin sections, dolomite content, and permeability data, the two main reservoir types, vuggy and fracture-vuggy, are systematically categorized. The influence of geological, development, and engineering factors on gas well productivity is analyzed using SHAP values. At the same time, to improve the accuracy and engineering practicability of gas reservoir productivity evaluation, the one-point productivity equation was refined, and open-flow capacity prediction charts for vuggy and fracture-vuggy reservoirs were constructed by combining the improved equation with the steady-state productivity equation. The results show that the dolomitization degree of vuggy reservoirs is lower than that of fracture-vuggy reservoirs, and the reservoir space types are mainly small dissolution pores or intergranular dissolution pores. The lithology of the fracture-vuggy reservoir is dolomite. The reservoir space of this type of reservoir is mainly composed of large dissolution pores and fractures, with a good matching relationship between fractures and pores. Based on the SHAP interpretation and analysis method, it is clear that cumulative water production, total acid fracturing fluid volume, gas-layer thickness, and porosity are the main factors affecting gas well productivity. Among them, the influence of cumulative water production and total acid fracturing fluid volume is the most significant, indicating that changes in the gas-water relationship and the effect of acid fracturing factors during development have a greater impact on gas well productivity. Based on the improved one-point productivity equation and the steady-state productivity equation, the open-flow prediction chart of vuggy and fracture-vuggy reservoirs is established. In predicting the gas well productivity of medium-deep reservoirs, with reconstruction scale and geological conditions similar to those of the HS 4 block, the chart’s predictions are in good agreement with field gas test and production test results. The single-well prediction error ranges from 2.2% to 6.5%, with an average error of 4.3%, indicating that the established chart has good applicability and predictive reliability. The research results can provide a theoretical and technical basis for reservoir classification evaluation, reasonable production allocation optimization, and new-well productivity prediction for carbonate gas reservoirs in the HS 4 block.
