The accurate prediction of shale oil production requires strong coupling between flow and geomechanics. However, traditional models often overlook the dynamic permeability damage induced by in-situ stress variations. To address this issue, our study establishes a fully coupled numerical simulation framework based on the virtual element method. This framework directly employs unstructured polyhedral grids generated by geological modeling software. This approach provides a distinct advantage over conventional methods, which rely on mesh reconstruction and exhibit severe distortion problems under large deformations. The model is validated using production data from a real field block, demonstrating the ability to accurately reproduce complex flow regime transitions and stress-induced production decline. Quantitative analysis identifies the Biot modulus as a key parameter governing reservoir stress sensitivity. Lower modulus values directly lead to substantial and sustained permeability damage. High fracture conductivity provides an initial productivity enhancement; however, it also accelerates stress redistribution around fractures that can cause severe localized permeability impairment in the vicinity of fracture roots over a relatively short production period. This work establishes a new integrated simulation model that couples geomechanical feedback with fluid flow, providing a quantitative engineering basis for effectively optimizing pressure-controlled production strategies and hydraulic fracturing design in shale oil reservoirs.

CO₂ sequestration into saline aquifers can significantly reduce atmospheric greenhouse gas concentrations, making it a key geological carbon storage technology for mitigating climate change and achieving carbon neutrality targets. However, current research predominantly focuses on reservoir saturation states, with limited understanding of dynamic mechanisms at the gas-liquid interface. In this study, microfluidic experiments were conducted at ambient temperature to investigate CO₂ drainage and imbibition under varying capillary numbers, incorporating the remobilization process driven by gas-water interphase mass transfer. Collectively, these three processes determine the temporal distribution of CO₂ and water phase saturations within the porous medium, thereby influencing the efficiency and long-term stability of CO₂ sequestration. With the increase of the capillary number, the sweep efficiency of CO₂ during drainage showed an upward trend, increasing to 54.71%. Moreover, this study provides an in-depth analysis of the distribution and morphological evolution of CO₂ under conditions where the aqueous phase is unsaturated. Results indicate that the asynchronous contraction of cluster interfaces results in a heterogeneous and dynamic dissolution process; the gas-water interface evolution of double-pore ganglia resembles the brine snap-off process; and singlet structures undergo shrinkage and deformation during the dissolution process. These findings elucidate the complex interactions between CO₂-water in porous media and underscore the critical roles of capillary forces and interfacial dynamics in geological carbon sequestration.