Understanding the dynamic characterization of the CO₂ miscible flooding process in low permeability reservoirs and its mechanism for oil recovery enhancement is crucial for controlling CO₂ miscible flooding sweep efficiency and further enhancing oil recovery. This study was conducted in a low permeability reservoir in Jilin, China, using both online nuclear magnetic resonance CO₂ miscible flooding and long-core CO₂ miscible flooding experiments. A refined dynamic characterization of the CO₂ miscible flooding process from the macroscopic core scale to the microscopic pore scale was achieved through multiple spatial online nuclear magnetic resonance testing methods. Analysis of dynamic characteristics of physical parameters was based on long-core displacement experiments and gas chromatography. This study summarizes the influence mechanism of CO₂ miscible flooding on enhanced oil recovery in low permeability reservoirs and demonstrates the feasibility of CO₂ miscible flooding. The results indicated that (1) CO₂ miscible flooding enables simultaneous oil recovery from micro-, meso-, and macropores, significantly improving displacement efficiency. (2) The recovery process unfolds in two stages: the initial CO₂ miscible flooding stage before gas breakthrough and the subsequent CO₂ miscible transport stage after gas breakthrough. (3) Both stages are instrumental in expanding the macroscopic swept range of CO₂, thereby enhancing oil recovery. (4) The miscibility of CO₂ with crude oil can affect the oil's composition. (5) The combined effect of miscible flooding and transport underpins the high displacement efficiency of CO₂ miscible flooding. Emphasizing these critical aspects could enhance oil recovery from CO₂ miscible flooding in field production.

The key to the efficient development of a tight reservoir is its accurate evaluation. In this study, the pore throat structure characteristics of sandstone samples in the study block were analyzed by high-pressure mercury injection technology. According to the characteristics of the capillary pressure curve, the sandstone samples in the study block were divided into three types: the first type has a reservoir permeability greater than 0.7 mD and a core mercury injection saturation of 96% with a good reservoir quality; the second type has a reservoir permeability ranging from 0.4 to 0.7 mD and a core mercury injection saturation of 80% with a moderate reservoir quality; and the third type has a reservoir permeability between 0.1 and 0.4 mD and a core mercury injection saturation of 50% with a poor reservoir quality. Also, high-resolution synchrotron radiation imaging and scanning electron microscopy were used to observe the pore throat structure, connectivity, and microscopic heterogeneity of sandstone samples, showing an increasing level of pore disconnection, serious microscopic heterogeneity, and poor reservoir performance as reservoir permeability declines. As mineral composition tests show, the lithology of the tight sandstone in the target block is mainly medium-grained and fine-grained feldspar lithic sandstone and the longitudinal heterogeneity of lithology and mineral components of tight sandstone is relatively weak at above the centimeter level. Besides, based on the high-pressure mercury injection test data, fractal theory is applied to calculate the fractal dimensions of the three types of reservoirs. The result shows a gradual increase in fractal dimensions with the decrease of reservoir quality, in which the closer the fractal dimension is to 3, the more serious the microscopic heterogeneity is, and the stronger the roughness of the pore surface is. As a result, the more heterogeneous the tight reservoir gets, the more likely the injected fluid is to flow along the developed and connected pore regions.

Tight reservoirs are sensitive to stress changes during fracturing and oil and gas production. Facing different production modes, the variation characteristics of rock permeability and pore structure need to be further clarified. In this study, using a self-built high temperature and pressure physical simulation device and NMR equipment, the influence of the stress loading method, cyclic loading, and loading rate on rock permeability and pore characteristics were analyzed, and the relationship between them was clarified. The permeability sensitivity under variable confining pressure (63.3%) was greater than that of variable flow pressure (46.4%). The damage rate decreased with repeated loading (63.3%-35.8%) and increased loading rate (53.1%-42.3%). As for the pore features, when the net stress increased, the volume variation range of micropores was greater than that of mesopores. The damage rate of permeability (63.3%) was obviously larger than that of pore volume (10.4%). The slope of the fitted curve of permeability and pore volume decreased evidently with loading times. The structure deformation of rock skeleton and the migration of cement had a great influence on permeability in the first loading. Later, it was mainly the bulk deformation of rock particles, the particles’ contact surface increasing and the seepage space shrinking slowly. Eventually, the permeability remained stable due to the limited pore compression. This study can provide a reference for designing reasonable production parameters and reducing formation damage.

The confinement effect in micro- and nanopores gives rise to distinct flow characteristics in fluids. Clarifying the fluid migration pattern in confined space is crucial for understanding and explaining the abnormal flow phenomena in unconventional reservoirs. In this study, flow characteristics of water and oil in alumina nanochannels were investigated with diameters ranging from 21 nm to 120 nm, and a heterogeneous viscosity flow model considering boundary fluid was proposed. Compared with the prediction of the HP equation, both types of fluids exhibit significant flow suppression in nanochannels. As the channel size decreases, the deviation degree increases. The fluid viscosity of the boundary region displays an upward trend as the channel size decreases and the influence of the interaction between the liquid and solid walls intensifies. The thickness of the boundary region gradually decreases with increasing pressure and eventually reaches a stable value, which is primarily determined by the strength of the interaction between the liquid and solid surfaces. Both the pore size and wettability are essential factors that affect the fluid flow. When the space scale is extremely small, the impact of wettability becomes more pronounced. Finally, the application of the heterogeneous flow model for permeability evaluation has yielded favorable fitting results. The model is of great significance for studying the fluid flow behavior in unconventional reservoirs.

REV-scale LBM (representative elementary volume scale lattice Boltzmann method) provides a possible way for the unified microscopic simulation of transscale seepage combined with pore-scale LBM. However, shown by numerical results, when simulated fluid flows in tight porous media with discrete microfractures or dispersed dissolution pore, the nonphysical oscillation phenomenon will occur in the region of relatively greater velocity gradient, due to the insufficient computational node caused by computational capability constraints. And for that reason, the increase in simulation scale under certain computational capability will be restricted. In order to solve this problem, this paper extends the application of the original LBM local refinement algorithm into REV-LBM and corrects the original REV-LBM velocity processing method, such that REV-scale LBM has a more reasonable local refinement algorithm. Through conventional computation example, this paper proves that the local refinement algorithm can maintain well computational accuracy while at least double the time efficiency and could save more than 30% of CPU time in the practical application. This algorithm has a great potential of application in simulating flows in larger size porous media with complex micro-nano structures and can provide a new idea to transscale simulation in porous media.