The fast settling rate of solid particles in the CO₂ fracturing fluid is a serious obstacle to ensuring the smooth progress of reservoir stimulation during conventional energy extraction, exerting a critical influence on enhancing both transformation efficiency and crude oil recovery. In this study, a fluid–solid coupling numerical model was developed, incorporating reservoir conditions and fluid properties, to simulate the settling behavior of solid particles in geological reservoir fluids. In addition, the effects of various geological factors and fluid parameters on particle settling were systematically examined. Furthermore, molecular dynamics theory, together with the analysis of intermolecular bonding interactions, was employed to elucidate the underlying mechanisms governing particle settling under different conditions. The findings of this study have the potential conclusion that the numerical model constructed in this study showed a high degree of fit (98.7%) with the experimental data, demonstrating the high applicability and good match of the numerical model. Furthermore, CO₂ viscosity is a significant factor influencing the differential settling of particles in reservoir fluids, and CO₂ fracturing fluid at 8 mPa·s can reduce the settling distance and velocity of solid particles to 3.2 m and 0.21 m/s, respectively. Simultaneously, both high reservoir pressure and a rough surface can effectively suppress the settling behavior of solid particles in CO₂ fracturing fluid, reducing the settling distance to 3.4 cm and 3.8 cm, respectively. However, the utilisation of high-temperature reservoirs at 383 K has been demonstrated to reduce the particle settling distance to 3.5 cm, a phenomenon that is evidently not conducive to the stimulation of deep, high-temperature reservoirs. The findings of this research endeavour have the potential to provide fundamental data for the utilisation of CO₂ fracturing fluids in reservoir stimulation and EOR.

Introduction: Efficient geothermal energy extraction has the potential to significantly alleviate the shortage of fossil energy, but low extraction efficiency and an insufficiently understood extraction mechanism remain key bottlenecks hindering its large-scale deployment. Method: This study develops a fluid–solid coupled numerical model based on the intrinsic physical properties of geological reservoirs to systematically analyze the energy extraction characteristics of geothermal systems. Simultaneously, the effects of key geological factors on fluid flow behavior within geothermal reservoirs are investigated. Furthermore, molecular dynamics simulations are employed to elucidate the microscopic mechanisms by which driving fluids facilitate geothermal energy extraction. Results: The results demonstrate that the thermo-hydraulic–mechanical (THM) numerical model was validated through a comparison with benchmark data reported in previous studies, exhibiting a high degree of agreement with geothermal extraction performance. The model further confirms that heat transport in the geothermal reservoir is characterized by a pronounced “tongue-in” isotherm pattern during the extraction process. Discussion: Lower initial temperatures of the driving fluid lead to more rapid geothermal energy extraction compared with higher initial temperatures, and the “tongue-in” phenomenon becomes increasingly pronounced as the initial injection temperature decreases. Moreover, increased injection pressure significantly enhances geothermal energy extraction efficiency; however, reduced pressure differentials markedly suppress the development of the “tongue-in” pattern and decrease reservoir permeability. In addition, water used as a heat-driving fluid achieves higher thermal extraction efficiency than water, while simultaneously exerting a stronger moderating effect on the permeability evolution of geothermal reservoirs. Conclusions: The simulation results obtained from the thermo-hydraulic-mechanical (THM) numerical model provide fundamental data to support the efficient development of geothermal reservoirs, while the associated analyses offer valuable insights into the selection of appropriate driving fluids for reservoirs with distinct geological characteristics.

Gravel particles are widely developed and randomly distributed in deep reservoirs of the Tarim Oilfield, western China. The mechanical behavior of conglomerate, the main component of the gravel layer, under varying confining pressure and different gravel content, remains poorly understood, especially in terms of the microscopic aspect, which limits the analysis of the variation patterns of underground engineering parameters. This study conducts triaxial compression tests on outcrop specimens from various stress levels to analyze the effects of stress state and stress differences on the mechanical parameters and failure modes. After that, a kind of numerical modeling method based on the discrete element method (DEM) is proposed, which considers the random distribution of gravel particles, to study the microscopic observation of mechanical characteristics and crack propagation of conglomerate under different stress state conditions. The experimental and numerical simulation results indicate that the horizontal strain before failure remains nearly constant in the axial direction while increasing linearly for the horizontal stress. And, it was observed that the volumetric failure was accompanied by gravel fragmentation, sliding, and falling. Numerical simulations reveal that cementation strength and gravel content significantly influence mechanical properties and failure modes, which are the main factors. This study provides some useful references for further understanding of the mechanical behavior and failure mechanisms of rocks in the gravel layer, in particular, the numerical modeling method for heterogeneous materials.