Carbonate reservoirs are one of the most important fossil fuel sources, and the acidizing stimulation is a practical technique for improving the recovery of carbonate reservoirs. In this study, the improved two-scale continuum model, including the representative elementary volume (REV) scale model and the upscaling model, is used to study the acidizing process with an isolated fracture. Based on this model, a comprehensive discussion is presented to study the effect of the physical parameters of the isolated fracture on the acidizing results and dissolution images, including the isolated fracture geometry, location, and morphology. Results show that the isolated fracture system is still the target system for the acidizing stimulation. The isolated fracture provides a limited contribution to the core porosity. The permeability of the core sample with fracture can be obviously increased only when the fracture penetrates through the whole sample. The existence of the isolated fracture reduces the consumption of acid solution to achieve a breakthrough. The acidizing curve is sensitive to the change of the length, aperture, and position of the isolated fracture. The acidizing curve difference corresponding to different rotation angles has not changed significantly for clockwise rotation and anticlockwise rotation groups.

Nanoparticles (NPs) have shown great potential in stabilizing foam for enhanced oil recovery (EOR). However, conventional NPs are difficult to recover and may contaminate produced oil, increasing operational costs. In contrast, superparamagnetic Fe₃O₄ NPs can be efficiently recovered using external magnetic fields, offering a sustainable solution for foam stabilization. In this study, Fe₃O₄ NPs were coated with SiO₂ using tetraethyl orthosilicate (TEOS) and further modified with dodecyltrimethoxysilane to enhance their hydrophobicity. The modification effects were characterized, and the optimal foam-stabilizing Fe₃O₄@SiO₂ NPs were found to have a contact angle of 77.01°. The foam system formed with α-olefin sulfonate (0.2 wt%) as the foaming agent and the optimal modified NPs exhibited a drainage half-life of 452 s. After foam-stabilization experiments, the NPs were recovered and reused, with the results indicating that three recovery cycles were optimal. Finally, visual microscopic displacement experiments demonstrated that the foam stabilized by modified NPs effectively mobilized clustered, membranous, and dead-end residual oil, increasing the recovery rate by 17.01% compared with unmodified NPs. This study identifies key areas for future investigation into the application of magnetic nanoparticles for enhanced oil recovery.

Long-term polymer flooding exacerbates reservoir heterogeneity, intensifying intra- and inter-layer conflicts, which makes it difficult to recover the remaining oil. Therefore, further improvement in oil recovery after polymer flooding is essential. In this study, a weak gel system was successfully synthesized, and possesses a distinct network structure that becomes more compact as the concentration of partially hydrolyzed polyacrylamide increases. The network structure of the weak gel system provides excellent shear resistance, with its apparent viscosity significantly higher than that of partially hydrolyzed polyacrylamide solution. The weak gel system exhibits typical pseudo-plastic behavior, which is a non-Newtonian fluid as well as a viscoelastic fluid. Additionally, the weak gel system’s elasticities exceed its viscosities, and longer crosslinking time further enhances the viscoelasticity. The weak gel system achieves superior conformance control and enhanced oil recovery in highly heterogeneous reservoirs compared to partially hydrolyzed polyacrylamide solutions. The weak gel system is more suited to low-permeability reservoirs with strong heterogeneity, as its effectiveness in conformance control and oil recovery increases with greater reservoir heterogeneity. Enhanced oil recoveries of the weak gel system in low-permeability sandpacks increase from 22% to 48% with a rise in permeability ratios from 14.39 to 35.64 after polymer flooding.

As the global energy demand grows, maximizing oil extraction from known reserves has become critical. The study of microfluidic flow and transport in porous media has become a key direction for future subsurface energy technologies. However, the high requirements of fabrication techniques and materials have constrained the progress of micro-scale experiments. In this study, we have innovatively proposed a microfluidic chip fabrication method based on ultraviolet laser, and a set of visualized microdrive platforms is developed to allow direct observation of two-phase flow processes at the pore scale. In this study, two pore structures—one with low porosity and high connectivity and the other with high porosity but low connectivity—were constructed to investigate the effect of pore structure on recovery. Two micromodels with different pore structures were fabricated, and water and surfactant drive experiments were conducted at different drive rates, respectively. The results show that increasing the replacement rate and introducing surfactant can somewhat improve the final recovery. Using surfactant is more effective in enhancing the recovery rate than increasing the replacement rate. The complexity of pore structure is one of the main factors affecting the formation of residual oil. The microfluidic experimental setup proposed in this study reduces the time and cost of conventional practical methods. It permits visualization of the oil drive process, demonstrating that the Norland Optical Adhesive 81 (NOA81) micromodel is a valuable tool in two-phase flow studies and its applications.