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.

Efficient flow simulation and optimization methods of hydraulic fracture morphology in unconventional reservoirs are effective ways to enhance oil/gas recovery. Based on the connection element method (CEM) and distribution of stimulated reservoir volume, the complex hydraulic fracture morphology was accurately described using heterogeneous node connection system. Then a new fracture connection element method (FCEM) for fluid flow in stimulated unconventional reservoirs with complex hydraulic fracture morphology was proposed. In the proposed FCEM, the arrangement of dense nodes in the stimulated area and sparse nodes in the unstimulated area ensures the calculation accuracy and efficiency. The key parameter, transmissibility, was also modified according to the strong heterogeneity of stimulated reservoirs. The finite difference and semi-analytical tracking were used to accurately solve the pressure and saturation distribution between nodes. The FCEM is validated by comparing with traditional numerical simulation method, and the results show that the bottom hole pressure simulated by the FCEM is consistent with the results from traditional numerical simulation method, and the matching rate is larger than 95%. The proposed FCEM was also used in the optimization of fracturing parameters by coupling the hydraulic fracture propagation method and intelligent optimization algorithm. The integrated intelligent optimization approach for multi-parameters, such as perforation number, perforation location, and displacement in hydraulic fracturing is proposed. The proposed approach was applied in a shale gas reservoir, and the result shows that the optimized perforation location and morphology distribution are related to the distribution of porosity/permeability. When the perforation location and displacement are optimized with the same fracture number, NPV increases by 70.58%, which greatly improves the economic benefits of unconventional reservoirs. This work provides a new way for flow simulation and optimization of hydraulic fracture morphology of multi-fractured horizontal wells in unconventional reservoirs.

Shale gas resources are widely distributed and abundant in China, which is an important field for strategic replacement and development of oil and gas resources. Shale gas reservoirs has adsorption gas, free gas. The structure of different scale media, such as organic pores, are difficult to describe. Therefore, flow behavior cannot be simulated by conventional method. In this paper, the micro-scale fluid migration in shale gas reservoirs was established in a single pore, which coupled surface diffusion, slip flow, and viscous flow. On this basis, the fractal scale relationship was applied to describe the distribution of pore radius, tortuosity, and surface roughness. Based on the comprehensive characterization of static structure characteristics of porous media, such as pore size distribution, pore shapes, tortuosity and surface roughness, and the dynamic pore size influenced by various stresses, the apparent porosity/permeability model of organic matter considering singlephase multi-migration mechanism was established. The gas migration in organic porous media was analyzed with the apparent porosity/permeability model. The results show that the small pores in organic matter are the main storage space of gas (more than 95% of the gas is stored in pores less than 10 nm), and the large pores are gas flow channel. At the same time, the apparent porosity/permeability model combined with conventional Darcy equation can be used to describe the single-phase gas flow in shale gas reservoirs.