The mutual coupling effect between the fluid flow and the in situ stress fields cannot be ignored during the development of natural fractured reservoirs (NFRs), such as in the waterflooding process. In this study, a discrete fracture model is proposed to simulate the rock deformation and two-phase flow behaviors of oil and water in the NFR. The numerical solution of the model is achieved via the finite-element method and control-volume finite-element method. The numerical simulator is verified using commercial software, and a perfect agreement is obtained. Finally, sensitivity analysis is conducted on the key parameters in the model, such as fracture parameters, matrix permeability, and injection intensity. Results show that the fluid–solid coupling effect gradually weakens with production time. The degree of the fluid–solid coupling on cumulative oil production becomes smaller as the permeability of the matrix increases. Fracture connectivity controls the velocity and direction of the water flood front. Water injection intensity directly affects the natural fracture opening deformation and well productivity. The research and the numerical results obtained in this paper can provide theoretical guidance for the optimal design of water flooding operations in NFR.

We study the gas–water transient imbibition and drainage processes in two-dimensional nanoporous media using our recently developed lattice Boltzmann model. To describe the microscopic molecular interactions, the model employs a pseudopotential that correlates the local density and interaction strength to perform simulation at a mesoscopic scale. The primary interest is ganglia dynamics in the nanoporous media affected by fluid and geometrical properties of the porous structure. We performed sensitivity analyses on the fluid and rock characteristics such as the Euler number, gas–water interfacial area, water film area, capillary pressure, pore size distribution, specific surface area, and wettability. The simulation results revealed the fingering nature of the nonwetting phase. In the imbibition process, the flow pathway of water results in isolated and trapped gas bubble clusters because of the strong attraction between water and solid surfaces. In the drainage process, the pressure difference between the gas phase and the water phase depends on both the capillary pressure and the disjoining pressure due to the presence of water film. Pore topography and specific surface area control the continuity of the fluid phases in the imbibition process. In nonwet systems, the water phase starts fingering in the nanoporous system. The present work elucidates the microscopic ganglia dynamics of gas–water two-phase flow in nanoporous media. The microscopic scale details will help establish the macroscopic flow equation to accurately predict two-phase flow in shale gas, tight oil, and caprock seals.

The storage of supercritical CO₂ in deep saline aquifers is essential for reducing carbon emissions, and the selection of an appropriate reservoir is a primary consideration for carbon sequestration. To investigate the impact of reservoir physical properties on the CO₂ storage capacity of saline aquifers, this study establishes a numerical simulation model of CO₂ storage in deep saline aquifers and utilizes the MRST toolbox to solve it by the finite volume method. The research thoroughly analyzes the influence of reservoir physical properties on the CO₂ migration process and CO₂ storage capacity of the saline aquifer layer. The results show that prolonged CO₂ injection involves a process of initially suppressing pressure and subsequently slowly diffusing it to the surroundings. Furthermore, the physical properties of the reservoir and the reservoir pressure significantly influence CO₂ burial in deep saline aquifers. Higher reservoir permeability and deeper burial depth result in enhanced CO₂ storage and faster CO₂ plume migration. However, the porosity and temperature of the reservoir have a negligible impact on CO₂ storage. Our research work provides a precise understanding of selecting suitable layers for CO₂ storage in deep saline aquifers, offering strong support for early predictions of carbon capture, utilization, and storage (CCUS).

The fluid–solid coupling effect is more pronounced in the process of deep coal seam development compared to shallow coalbed methane, exerting a greater influence on production, and cannot be disregarded. Throughout the extraction process, the interaction between effective stress and gas desorption triggers deformation within the coal seam, leading to dynamic changes in both porosity and permeability. This paper has developed a fully coupled gas flow and deformation model that contains the coal matrix and discrete fractures to describe the dynamic gas seepage behavior and deformation of deep coal seams within a coupled wellbore–hydraulic fractures–matrix system. The model's validity is corroborated through the examination of fracture aperture, employing the finite element numerical simulation capabilities of COMSOL Multiphysics. Subsequent to the model's validation, an in-depth investigation into the permeability and production variations under diverse parametric conditions is conducted. This analysis also encompasses the assessment of hydraulic fracture geometry's impact. The simulation outcomes reveal that the permeability alterations during coal seam development are subject to the counteracting influences of gas desorption and effective stress. Moreover, it is observed that an increase in the Langmuir volume strain constant and initial porosity correlates with enhanced production, whereas a diminution in the hydraulic fracture compression coefficient leads to increased cumulative production. Notably, the optimal production is attained when hydraulic fractures are oriented vertically yet asymmetrically relative to the horizontal well.

In the process of acidizing carbonate reservoirs, dissolution is employed for reservoir modification to enhance recovery rates. This study establishes a numerical model at the pore scale for acid-rock reaction flow based on a microscopic continuum medium model, integrating phase-field theory and component transport models. Subsequently, the results of the Darcy-Brinkman-Stokes model are compared to those of the arbitrary Lagrange-Euler method to validate the accuracy of the model. Finally, the flow behavior of the acid solution at the pore scale and the complex dissolution mechanisms in carbonate reservoirs are analyzed. The research indicates that the microscopic pore-scale dissolution in carbonate reservoirs mainly manifests as five dissolution modes: uniform dissolution, compact dissolution, conical wormholes, dominant wormhole, and ramified wormholes. Different distributions of microfractures will alter the flow state of the acid solution and the rock-acid reaction process within the pores. Once the wormhole breakthrough occurs, there is an increased probability of acid flow through the wormhole to the outlet, leading to a decrease in the effectiveness of the acidizing carbonate reservoirs. A proper understanding of pore-scale acid-rock reaction laws is of great significance for the development of carbonate oil and gas reservoirs.