Pore-Scale Flow Dynamics and Mobilization of Remaining Oil Under Different Waterflooding Regimes in Deepwater Sandstone Reservoirs

Deepwater sandstone reservoirs are commonly developed under high-intensity injection and production conditions because of a limited number of wells, large injector–producer spacing, and offshore processing constraints. Injection rate variations alter the balance between viscous and capillary forces, thereby affecting oil–water displacement and remaining oil mobilization. However, the pore-scale effects of injection rate and rate adjustment sequence remain insufficiently understood. Here, a two-dimensional polydimethylsiloxane (PDMS) micromodel replicating the pore structure of a real deepwater sandstone reservoir was used to investigate four regimes: constant low-rate, constant high-rate, low-to-high-rate, and high-to-low-rate waterflooding. The low-to-high-rate regime achieved the highest final oil recovery factor of 88.41%, exceeding the constant low-rate, constant high-rate, and high-to-low-rate regimes by 6.54, 3.86, and 3.97 percentage points, respectively. Constant low-rate waterflooding gave the lowest recovery factor of 81.87% and a total areal remaining oil saturation of 18.13%, compared with 15.44% under constant high-rate conditions. Under low-rate flooding, wall-attached oil, elongated ganglia, and oil droplets accounted for 90.18% of the remaining oil, indicating limited mobilization of oil retained by interfacial effects and local capillary trapping. Increasing the rate reduced the total areal remaining oil saturation from 44.04% to 11.58%, mainly by mobilizing oil clusters and elongated ganglia, whereas decreasing the rate reduced it only from 16.52% to 15.55%. At the same cumulative injected volume of 1 PV, the total areal remaining oil saturation under high-rate flooding was 27.52 percentage points lower than that under low-rate flooding, indicating faster early-stage mobilization, while the low-rate stage retained more oil available for subsequent mobilization. These results show that waterflooding performance depends on both injection rate and flow history. A low-to-high-rate sequence combined relatively stable early-stage displacement with enhanced subsequent mobilization, providing pore-scale evidence that injection-rate history can influence displacement pathways and remaining-oil mobilization in deepwater sandstone reservoirs.