The development of natural gas in tight sandstone gas reservoirs via CH₄-CO₂ replacement is promising for its advantages in enhanced gas recovery (EGR) and CO₂ geologic sequestration. However, the degree of recovery and the influencing factors of CO₂ flooding for enhanced gas recovery as well as the CO₂ geological rate are not yet clear. In this study, the tight sandstone gas reservoir characteristics and the fluid properties of the Sulige Gasfield were chosen as the research platform. Tight sandstone gas long-core displacement experiments were performed to investigate (1) the extent to which CO₂ injection enhanced gas recovery (CO₂-EGR) and (2) the ability to achieve CO₂ geological storage. Through modification of the injection rate, the water content of the core, and the formation dip angle, comparative studies were also carried out. The experimental results demonstrated that the gas recovery from CO₂ flooding increased by 18.36% when compared to the depletion development method. At a lower injection rate, the diffusion of CO₂ was dominant and the main seepage resistance was the viscous force, which resulted in an earlier CO₂ breakthrough. The dissolution of CO₂ in water postponed the breakthrough of CO₂ while it was also favorable for improving the gas recovery and CO₂ geological storage. However, the effects of these two factors were insignificant. A greater influence was observed from the presence of a dip angle in tight sandstone gas reservoirs. The effect of CO₂ gravity separation and its higher viscosity were more conducive to stable displacement. Therefore, an additional gas recovery of 5% to 8% was obtained. Furthermore, the CO₂ geological storage exceeded 60%. As a consequence, CO₂-EGR was found to be feasible for a tight sandstone gas reservoir while also achieving the purpose of effective CO₂ geological storage especially for a reservoir with a dip angle.

The swelling effect of high-pressure carbon dioxide (CO₂) in coal seam is obvious. In the restrained deep formation, it is converted to stress acting on the wellbore and the caprock. The action stress is concentrated near the wellbore and poses a threat to the cement-formation interface. Due to interface failure to micro-annulus, wellbore integrity will be lost and this will have an impact on carbon dioxide-enhanced coalbed methane recovery (CO₂-ECBM) and storage. In this paper, the pseudo-steady pressure distribution and steady pressure distribution of CO₂ injection process were established after considering the change in permeability of coal seam injected with high-pressure supercritical CO₂, and the vertical stress distribution model was derived. A one-dimensional radial numerical simulation formed by iterative method was established. A model for calculating the failure length at the cement-formation interface is obtained, and the shear stress and debonding length at the interface at various injection rates and times are calculated. The results show that the shear stress on the cement-formation interface has the maximum magnitude on the height of the interface between coal seam and caprock. The shear stress generated by coal swelling may break the fragile cement-formation interface into a narrow debonding interface. The injection rate has an influence on the interface failure length. For the same total injection amount, low injection rate is beneficial to protect the cement-formation interface integrity. This study provides a reference for the design of maximum injection speed for CO₂-ECBM and storage to avoid leakage.

A three‐dimensional two‐phase Lattice Boltzmann model was developed and validated for the fundamental phenomena of gas‐water transport in tight porous media considering microscopic forces, namely, the electrostatic and solid‐liquid intermolecular forces. The thickness of the water film adhering to the porous media surface was calculated based on the principle of thermodynamic equilibrium and the gas‐water electrostatic potential energy. The Lattice Boltzmann model simulations focused on the effects of the microscopic forces and water film thickness on the gas‐water transport in tight porous media. The fluid flow in the porous media was simulated under different conditions for the characteristic length, interfacial tension, and displacement pressure gradient. The results confirmed that the gas‐water transport is strongly affected by the microscopic forces in tight porous media and that the transport process is accompanied by a high seepage resistance. The seepage resistance is more pronounced in the case of smaller pores because the adhering water film is thicker and more stable. During the transport process, the water film may disintegrate under certain conditions, which would enhance the gas flow in the porous media. However, it is difficult to effectively improve the gas flow by increasing the displacement pressure gradient under microscopic forces; this can be attributed to the accumulation of water or increased seepage resistance dictated by the interfacial tension, which occurs more frequently with smaller pores. This paper provides a promising new perspective for efficiently improving the Lattice Boltzmann model for transport trends considering microscopic forces.

Accuracy defects exist when modeling fluid transport by the classical capillary bundle model for tight porous media. In this study, a three-dimensional simplified physical model construction method was developed for tight sandstone gas reservoirs based on the geological origin, sedimentary compaction and clay mineral-cementation. The idea was to reduce the porosity of the tangent spheres physical model considering the synergistic effect of the above two factors and achieve a simplified model with the same flow ability as the actual tight core. Regarding the wall surface of the simplified physical model as the boundary and using the Lattice Boltzmann (LB) method, the relative permeability curves of gas and water in the simplified model were fitted with experimental results and a synergistic coefficient could be obtained, which we propose for characterizing the synergistic effect of sedimentary compaction and clay mineral-cementation. The simplified physical model and the results simulated by the LB method are verified with the experimental results under indoor experimental conditions, and the two are consistent. Finally, we have carried out a simulation of gas flooding water under conditions of high temperature and high pressure which are consistent with the actual tight sandstone gas reservoir. The simulation results show that both gas and water have relatively stronger seepage ability compared with the results of laboratory experiments. Moreover, the interfacial tension between gas and water is lower, and the swept volume is larger during placement. In addition, the binding ability of the rock surface to the water film adhered to it becomes reduced. The method proposed in this study could indicate high frequency change of pores and throats and used to reflect the seepage resistance caused by frequent collisions with the wall in microscopic numerical simulations of tight sandstone gas reservoirs.

In the process of reservoir exploration, the weak horizontal structural surface easily slips and cracks, and casing shearing often occurs during the formation process, which significantly affects the economic viability and effective development of an oilfield. Additionally, repeated damage at the same casing position indicates the possibility of numerous cracks in the weak structural surface. In this study, we propose the geomechanical stick–slip theory to verify the above phenomenon. The stress calculation method for the weak horizontal structural surface in the upper part of the reservoir is devised under the influence of inter-regional pore pressure differences. Based on the process of accumulation–release–reaccumulation–rerelease in the formation and deformation processes, we construct the calculation model of shear stress release and slips on the cracked surface. While considering the influence of water inflow on the cracked surface, the pressure exerted on the formation stick–slip is analyzed. Then, the model was verified by the data of block X in the Daqing oilfield. The results demonstrate that under wet conditions, the maximum static and dynamic frictional stresses on the cracked surface decrease significantly, and this makes the cracked surface more prone to a greater slip degree. After the weak horizontal structural surface cracks and slips occur for the first time, the pressure difference between regions required for formation of the next slip decreases significantly. With the continuous formation of slips, the slip range gradually expands with an increase in inter-regional pressure variance. The research work in this study provides a theoretical basis for the prevention and control of casing damage in oil development zones.