Pore-Scale Wettability Alteration and Optimal Interfacial Tension Synergy in Enhanced Tight Oil Imbibition

Summary Pressure supplementation before fracturing operations refers to the technical measure conducted before the main fracturing or the next stage of staged fracturing, where chemical systems are preinjected to improve rock wettability and reduce interfacial tension (IFT), thereby stabilizing the formation pressure at its original level. By doing so, it enhances the overall dynamic behavior of the reservoir, thereby improving fracturing stimulation effectiveness and increasing matrix recovery rates through enhanced imbibition. The change in wettability from oil-wet to water-wet and the decrease in IFT are usually regarded as the main imbibition mechanisms. However, the effect of pore size on wettability change and the optimal range of IFT for imbibition remain unclear. In this paper, based on nuclear magnetic resonance (NMR) imbibition experiments, we investigate the interfacial interactions between different imbibition fluids and cores with different mineral compositions, as well as the enhanced imbibition mechanism, from the perspectives of pore wettability changes and optimal IFT ranges. The contribution of various influencing factors to imbibition recovery is also analyzed. The mineral component differences between shale and tight sandstone make them, respectively, exhibit oil-wet and weakly water-wet properties. Spontaneous imbibition mainly occurs in relatively small pores, showing mixed wettability. As the pore radius increases, the pores become more oil-wet. The crude oil displaced by the imbibition of shale and tight cores mainly comes from small pores, with contribution degrees reaching 53.3% to 60.7% and 39.1% to 72.2%, respectively. After enhanced imbibition, the wettability alteration degrees of micropores, small pores, and mesopores in the core gradually decrease, and the corresponding imbibition efficiency gradually decreases. The wettability change in the small pore range (10–100 nm) has a greater impact on the imbibition recovery rate, which is conducive to the precise assessment of tight oil production. The optimal IFT ranges corresponding to shale and tight sandstone are 0.09~6.90 mN/m and 0.12~9.40 mN/m, respectively. Petroleum sulfonates and nanofluids achieve optimal imbibition recovery by synergistically reducing contact angles to 60° (strongly water-wet) and targeting small pores, where low IFT (0.5~0.6 mN/m) enables capillary-driven oil deformation, contributing 53~72% of total recovery, whereas low-salinity water (LSW) and Bohai drilling (BH) systems exhibit weak wettability reversal (88.8°) and rely on inefficient gravity drainage in oil-wet mesopores, limiting small-pore efficiency to 39~60%. The weight coefficients of the factors influencing the enhanced imbibition of tight oil are as follows: core characteristic value wettability IFT. The physical properties of the reservoir itself are the fundamental restrictive factors for the imbibition effect. Wettability affects the capillary force direction and the imbibition recovery rate. IFT should be optimized in coordination with other factors. Pursuing ultralow IFT alone may have limited effects. The research results of this paper are helpful for designing scientific enhanced oil recovery (EOR) strategies in tight oil reservoirs.