Liang Zhao

In the late high water cut stage of medium- and high-permeability sandstone reservoirs, remaining oil becomes highly dispersed, and rational optimization of the water injection rate is crucial for further recovery improvement. However, a quantitative relationship between pore-scale remaining oil mobilization and macroscopic displacement efficiency is still lacking, limiting mechanistic guidance for field-scale rate optimization and water cut control. To address this issue, variable-rate waterflooding experiments were conducted on medium- and high-permeability sandstone cores to establish the relationships among displacement rate, injected pore volume multiples, and oil displacement efficiency and to identify the optimal rate. In addition, an X-CT-based heterogeneous pore-scale geometric model and a series of idealized pore-throat models were used for oil–water two-phase flow simulations. Combined with an orthogonal experimental design, the effects of displacement rate, wettability, oil viscosity, interfacial tension, and pore structure parameters on remaining oil mobilization and displacement efficiency were systematically evaluated. The results indicate an optimal displacement rate of 2–3 mL/min. At low rates, remaining oil cannot be effectively mobilized, whereas excessively high rates intensify fingering and channeling along high-capacity pathways, reducing the final displacement efficiency. Simulations further show that a moderate rate increase markedly lowers remaining oil saturation, while overly high rates induce severe channeling. Orthogonal analysis reveals that displacement rate and wettability are the dominant factors, with normalized weights of 46.3% and 30.5%, respectively. Larger pore diameters, smaller pore-throat ratios, and higher coordination numbers reduce mobilization pressure and remaining oil saturation. This work elucidates pore-scale remaining oil mobilization kinetics under variable-rate waterflooding and provides a quantitative microscopic basis for rate optimization and fine-scale remaining oil exploitation in mature waterfloods.

Shale gas production dynamics display strong heterogeneity and nonlinearity, posing challenges to conventional analytical methods. This study applies fractal theory to analyze long-term production data from 178 global shale gas fields by calculating Hurst exponent (H) and fractal dimension (D). Results show 60.7% of fields are suitable for fractal analysis, with H values of 0.64–0.92 and D values of 1.0–1.9, indicating significant long-term memory and structural complexity. Cluster analysis reveals two distinct production patterns: stable trend (13.0%) and fluctuating trend (87.0%). Key innovations include: (1) extending fractal theory from static reservoir characterization to dynamic production analysis; (2) establishing a fractal-based production classification system; and (3) defining applicability conditions for fractal analysis in shale gas evaluation. This study demonstrates fractal theory’s effectiveness as a quantitative tool for production dynamics analysis, EUR estimation, and development strategy optimization.

Understanding pore-scale morphology and distribution of remaining oil in pore space are of great importance to carry out in-depth tapping of oil potential. Taking two water-wet cores from a typical clastic reservoir in China as an example, X-ray CT imaging is conducted at different experimental stages of water flooding and polymer-surfactant (P-S) flooding by using a high-resolution X-ray microtomography. Based on X-ray micro-CT image processing, 3D visualization of rock microstructure and fluid distribution at the pore scale is achieved. The integral geometry newly developed is further introduced to characterize pore-scale morphology and distribution of remaining oil in pore space. The underlying mechanism of oil recovery by P-S flooding is further explored. The results show that the average diameter of oil droplets gradually decreases, and the topological connectivity becomes worse after water flooding and P-S flooding. Due to the synergistic effect of “1 + 1 > 2” between the strong sweep efficiency of surfactant and the enlarged swept volume of the polymer, oil droplets with a diameter larger than 124.58 μm can be gradually stripped out by the polymer-surfactant system, causing a more scattered distribution of oil droplets in pore spaces of the cores. The network-like oil clusters are still dominant when water flooding is continued to 98% of water cut, but the dominant pore-scale oil morphology has evolved from network-like to porous-type and isolated-type after P-S flooding, which can provide strong support for further oil recovery in the later stage of chemical flooding.