Liquid invasion damage plays a main role in the formation damage of low-permeability sandstone reservoirs. The long-term retention of working fluid in the formation will cause serious water blocking damage. In order to research the quantitative prediction of liquid flowback in low-permeability sandstone reservoirs, a new method for quantitative prediction of liquid flowback based on the capillary bundle model was proposed, which took into account the boundary layer effect. Besides, taking the low-permeability sandstone samples of Penglaizhen formation in the Sichuan basin as an example, the quantitative prediction of liquid flowback was carried out. Finally, a series of experiments including gas displacement experiment and nuclear magnetic resonance experiment were conducted to examine the validation of the new method for quantitative prediction of liquid flowback. The study indicates that the results of quantitative prediction were in good agreement with the experimental results. Liquid flowback is closely related to pore structure, boundary layer effect, and displacement pressure in low-permeability sandstone reservoirs. For the sandstone sample with a permeability of 5.5 mD, most of the liquid could be displaced out at 1 MPa, and liquid saturation in the sandstone sample tends to be stable at 32%; for the sandstone sample with a permeability of 0.0349 mD, liquid flowback process is more durable, thereby the cumulative mass of liquid flowback and liquid saturation change gradually, and liquid saturation tends to be stable at 55%. This study not only provides an insight into the microscope mechanisms of liquid flowback but also predicts the cumulative mass of liquid flowback and liquid saturation accurately.

The in situ emulsification synergistic self-profile control system has wide application prospects for efficient development on offshore oil reservoirs. During water flooding in Bohai heavy oil reservoirs, random emulsification occurs with superimposed Jamin effects. Effectively utilizing this phenomenon can enhance the efficient development of offshore oilfields. This study addresses the challenges hindering water flooding development in offshore oilfields by investigating the emulsification mechanism and key influencing factors based on oil–water emulsion characteristics, thereby proposing a novel in situ emulsification flooding method. Based on a fundamental analysis of oil–water properties, key factors affecting emulsion stability were examined. Core flooding experiments clarified the impact of spontaneous oil–water emulsification on water flooding recovery. Two-dimensional T1–T2 NMR spectroscopy was employed to detect pure fluid components, innovating the method for distinguishing oil–water distribution during flooding and revealing the characteristics of in situ emulsification interactions. The results indicate that emulsions formed between crude oil and formation water under varying rheometer rotational speeds (500–2500 r/min), water cuts (30–80%), and emulsification temperatures (40–85 °C) are all water-in-oil (W/O) type. Emulsion viscosity exhibits a positive correlation with shear rate, with droplet sizes primarily ranging between 2 and 7 μm and a viscosity amplification factor up to 25.8. Emulsion stability deteriorates with increasing water cut and temperature. Prolonged shearing initially increases viscosity until stabilization. In low-permeability cores, spontaneous oil–water emulsification occurs, yielding a recovery factor of only 30%. For medium- and high-permeability cores (water cuts of 80% and 50%, respectively), recovery factors increased by 9.7% and 12%. The in situ generation of micron-scale emulsions in porous media achieved a recovery factor of approximately 50%, demonstrating significantly enhanced oil recovery (EOR) potential. During emulsification flooding, the system emulsifies oil at pore walls, intensifying water–wall interactions and stripping wall-adhered oil, leading to increased T2 signal intensity and reduced relaxation time. Oil–wall interactions and collision frequencies are lower than those of water, which appears in high-relaxation regions (T1/T2 > 5). The two-dimensional NMR spectrum clearly distinguishes oil and water distributions.