As an effective technology for enhancing oil recovery, low-salinity water flooding requires further investigation into its microscopic displacement mechanisms and the regulatory roles of key ions. Based on microscopic visualization displacement experiments, this study systematically investigated the effects of injected water salinity, key ion types (Na⁺, K⁺, Ca²⁺, Mg²⁺, HCO₃⁻, CO₃²⁻, SO₄²⁻, and OH⁻), and their concentrations on crude oil displacement behavior in both high- and low-permeability zones. Experimental results indicate that no significant correlation exists between displacement efficiency and injected water salinity in high-permeability zones. In low-permeability zones, displacement efficiency increases with decreasing salinity, peaking at 26.5% when injected water salinity reaches 5000 mg/L. The cation displacement efficiency in the formation, from highest to lowest, is Ca²⁺ > K⁺ > Mg²⁺ > Na⁺. The anion displacement efficiency, from highest to lowest, is OH⁻ > SO₄²⁻ > CO₃²⁻ > HCO₃⁻. When the CaCl₂ concentration decreased from 100 wt% to 50 wt%, the displacement effect in the low-permeability zone improved further, indicating that a higher concentration of the divalent cation Ca²⁺ is not necessarily better. In medium-to-high salinity formation water reservoirs, and under conditions where the influence of clay minerals is disregarded, ion type and reservoir permeability are the most significant factors affecting oil recovery efficiency. These findings provide theoretical support for elucidating the micro-dynamic mechanisms of low-salinity water flooding in low-permeability zones and optimizing injection water formulations.

To address the insufficient consideration of osmotic pressure in existing studies on water huff-and-puff in tight oil reservoirs, this paper introduces both osmotic and capillary pressures into two-phase flow theory and develops a full-cycle model for low-salinity water injection. The effects of salinity, injection rate, and soaking time on pressure, saturation, and salt concentration are analyzed. Results show that lower salinity enhances osmotic drive and improves recovery. Specifically, 1000 mg/L yields the highest recovery (10.94%) and an osmotic gradient of ~3.9 MPa. Capillary pressure acts synergistically with osmotic pressure during the soaking stage, promoting spontaneous imbibition and fluid redistribution. An optimal injection rate exists: excessive rates reduce swept volume, while very low rates prolong the cycle. Quantitatively, 80 m³/d is preferred (recovery 10.94%) over 40 m³/d (11.13%) as it halves the injection time with comparable recovery. There is also an optimal soaking time beyond which incremental gain diminishes. Recovery rises from 9.32% at 20 d to 10.94% at 40 d, with only 0.28% and 0.20% gains afterward; thus, 40 d is optimal. The model captures osmotic-driven behavior and reveals the secondary displacement effect during soaking, supporting parameter optimization.

To elucidate the dominant mechanism by which pore-throat structures influence imbibition oil recovery in tight sandstone reservoirs, this study conducted experiments on natural core samples obtained from tight sandstone reservoirs. The pore-throat structures of the cores were characterized using scanning electron microscopy (SEM) and high-pressure mercury intrusion porosimetry (MIP). Based on this, spontaneous imbibition experiments combined with nuclear magnetic resonance (NMR) technology were employed to monitor real-time signal intensity changes of fluorinated oil and water within pores of different sizes. This approach identified the dominant driving forces for imbibition in various pore-throat types and quantitatively characterized the contribution of different pore scales to imbibition oil recovery in tight sandstone reservoirs. The results show that higher permeability corresponds to greater fluid displacement efficiency. In reservoirs with higher permeability, gravity serves as the dominant driving force during imbibition, and macropores (pore diameter > 1 μm) contribute the majority of the imbibition oil recovery. In reservoirs with lower permeability, both gravity and capillary forces play significant roles in imbibition. Fluid displacement mainly occurs in the early stage of imbibition, with weaker displacement in the later stage. Macropores contribute most of the imbibition recovery, mesopores (pore diameter 0.1–1 μm) contribute a small portion, while micropores (pore diameter 0.025–0.1 μm) and nanopores (pore diameter < 0.025 μm) also contribute marginally. Whether the dominant force is gravity or capillary force, macropores and mesopores are the primary sources of imbibition oil recovery, indicating that oil content and pore connectivity are crucial factors influencing imbibition efficiency. This study provides useful guidance for enhancing oil recovery through spontaneous imbibition in tight sandstone reservoirs.

To address the unclear microscopic mechanisms of water huff-n-puff in tight reservoirs under the influence of salinity, a visual physical model for microscopic flow in fracturing fluid displacement was constructed. It was clarified that the fluid displacement mechanism during fracturing fluid displacement is jointly governed by three mechanisms: pressure differential displacement, capillary force imbibition, and ion osmosis, which breaks through the traditional understanding only considering “fracturing fluid displacement and imbibition for energy supplementation.” Through multi-method and multi-scale approaches, the microscopic mobilization mechanism of fracturing fluid displacement under the influence of salinity was elucidated, and the main controlling factors were analyzed. The results indicate that reducing the salinity of injected water can enhance oil recovery, and the recovery factor increases with reservoir permeability, shut-in time, and injection pressure. Reservoir permeability and injected water salinity have a greater impact on the performance of water huff-n-puff, followed by shut-in time and injection pressure. Although low-salinity water flooding tends to induce viscous fingering, which reduces the sweep efficiency of the injected water, it enhances capillary imbibition, effectively stripping residual oil from low-permeability matrices and dead-end pores, thereby ultimately improving oil recovery. This study provides theoretical support for enhancing recovery in tight oil reservoirs using fracturing fluid displacement.