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This paper presents the results of an analytical model for the capillary rise in nano-channels considering the effect of inherent surface roughness. The model was derived using the classical Lucas-Washburn model and the momentum conservation equation, while considering the inherent surface roughness of an equivalent porous medium layer (PML). The calculated frictional resistance due to the PML reflects the friction of fluid flowing through nano-channels. The capillary imbibition in the nano-channels is in the range of low-Reynolds-number flow, and because of its low flow-rate, the inertia force can be ignored in this study. This analytical model was validated by comparing it with nano-capillary rise experiments and other simulated values such as the classical Lucas-Washburn (LW) model and the classical LW model with a 40% fluid viscosity increment. The analytical model produces the closest results to those obtained in the experiments, and it can explain the lower-than-expected (using the LW equation) height of capillary rise obtained in the experiments.

Both wettability alteration and low interfacial tension (IFT) are important mechanisms of surfactants for enhancing oil recovery. In the imbibition process, surfactant solution invades the matrix, lowering IFT and altering the contact angle; these factors change the distribution of oil as well as the magnitude and direction of capillary force. Although a lot of research has been done in modeling countercurrent imbibition, less attention has been paid to comparing which effect plays a more important role in the imbibition process. A mechanistic model was used to study the surfactant solution imbibition process in porous media with subnanometer and nanometer capillaries, and the approximated diffusion coefficient was used to simplify the calculation. The simulated calculation demonstrates that, in contrast to low IFT, the change in wettability is the major mechanism for improving tight rock imbibition recovery, and this confirms that the change in wettability contributes more than lower IFT to the ultimate imbibition recovery.

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.

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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.