Tailoring Water-Gas Ratios to Saturation Distribution for Improved Oil Recovery in Low-Permeability Reservoirs.

Water-gas alternation technology (WAG) is considered to be one of the methods that can effectively improve the effect of the CO2 flooding in heterogeneous reservoirs. The proportion of WAG and the timing of WAG adjustment are key factors affecting the oil displacement effect. This article analyzes the influence of adjusting the WAG ratio on the oil recovery effect of heterogeneous rock cores at different gas flooding stages based on gas flooding experiments. Second, the influence of WAG ratio changes on the recovery rate of displacement experiments under different saturation distributions was studied through numerical simulation. Finally, the oilfield model currently in production was used to optimize the WAG ratio adjustment of the reservoir recovery as a constraint condition. Moreover, the correlation between the fluid distribution of the reservoir and the timing of WAG adjustment was verified. The displacement experiment shows that adjusting the WAG ratio has a significant impact on the displacement effect of crude oil under the same heterogeneous conditions. After adjusting the WAG ratio from 1:2 to 2:1 at 0.5 HCPV and 1 HCPV, the final RF showed significant changes. There is an optimal timing for adjusting the WAG ratio under the same heterogeneity. If the WAG ratio is increased earlier, it will lead to a decrease in the CO2 injection volume and reduce the effectiveness of CO2 flooding. If the WAG ratio is increased later, it will lead to the formation of gas channeling channels and affect the effect of adjusting the WAG ratio on flooding.

Transport Behavior of Oil in Mixed Wettability Shale Nanopores.

Shale oil reserves play an important role in the oil & gas industry. The investigation of oil transport behavior in shale nanopores is crucial in the successful exploitation of shale oil reservoirs. However, the transport mechanisms of oil in shale nanopores are still not understood. In this paper, a model for oil transport through a single nanopore was established by considering mixed wettability, surface roughness, varying viscosity, and the effects triggered by adsorbed organic matter. The organic surface ratio of a single nanopore was used to quantify mixed wettability, while the effects of adsorbed organic matter were estimated by the surface coverage and the adsorption thickness. The entire mathematical model was simplified into several equations to discuss the contributions of each mechanism. The results showed that to accurately predict the oil transport properties in mixed wettability shale nanopores, it is necessary to consider varying viscosity, wettability alteration, and the oil molecule structure. Adsorbed organic matter led to increase in oil flow capacity by altering the surface wettability. However, the oil flow capacity was greatly reduced when varying viscosity was considered. Additionally, the contributions of each mechanism varied with the pore type. Furthermore, increasing surface roughness significantly reduced the oil flow capacity in both organic and inorganic nanopores. This work provides a better understanding of oil transport behavior in mixed-wettability shale nanopores and a quantitative framework for future research.