Zhiyuan Du

Water retention after imbibition and the recovery response to low-salinity injection suggest that capillarity alone does not describe all fluid exchange in tight formations. How osmotic forces influence successive injection, soaking, and production stages in a fractured reservoir therefore requires further examination. We constructed a simulator that combines aqueous salt transport with two-phase flow and represents hydraulic fractures by assigning equivalent properties to the intersected grid cells. A comparison with an independent simulator was used to assess the computed saturation response. Sensitivity cases varied in brine salinity, shut-in duration, injection rate, branch position, and network geometry; pressure, aqueous saturation, salt distribution, and produced oil were examined together. With 4800 m³ injected at 80 m³/d and a subsequent 40 d soak, the 1000 mg/L case produced 13,741.24 m³ of oil and recovered 17.28% of the initial oil volume. The corresponding values at 50,000 mg/L were 9507.86 m³ and 11.95%. Thus, reducing salinity added 4233.38 m³ of oil and 5.33 percentage points of recovery, equivalent to a 44.60% increase relative to the reported high-salinity recovery factor. Extending shut-in beyond 40 d provided progressively smaller benefits. A faster injection schedule reduced the operating time at a fixed water volume but also favored early water return; 80 m³/d provided a useful compromise within the tested range. Placing branches close to the well raised recovery to 22.35%, versus 17.28% for the unbranched fracture. This improvement was 5.07 percentage points, or 29.34% relative to the baseline. In the network cases, matrix blocks enclosed by fractures supplied most of the recovered oil, while more isolated rock retained substantial oil. Taken together, the simulations link the benefit of dilute injection water to fracture access and the time available for matrix exchange. For the assumptions and cases examined, a 1000 mg/L brine, an 80 m³/d injection schedule, a 40 d soak, and branches close to the well provide a favorable operating combination.

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.