The process of spontaneous imbibition is the basis of oil recovery from tight oil reservoirs. In this study,spontaneous imbibition experiments were conducted based on tight oil weakly hydrophilic sandstone cores from the Honghe oilfield in the Ordos Basin. Four different types of surfactants,such as nonionic Triton X-100,nonionic Tween-80,cationic dodecyl trimethyl ammonium bromide,and anionic sodium dodecyl benzene sulfonate,were separately dissolved in 30 g/L potassium chloride solution as simulated formation water. The effects of surfactant type on spontaneous imbibition were analyzed,and the results indicated that,because the nonions are adsorbed on the surface via Van der Waals force and adsorb H⁺ through hydrogen bonds,the two nonionic surfactants altered the wettability of the core from weakly hydrophilic to strongly hydrophilic,the recovery rate was relatively high. The Triton X-100 was selected for subsequent spontaneous imbibition experiments by changing the mass concentration to adjust interfacial tension. It was found that the maximum recovery rate was 32% when the Triton X-100 mass concentration was 0.1%,which indicates that the enhanced recovery rate of spontaneous imbibition requires a sufficiently low wettability factor and a suitably high interfacial tension factor. Finally,the surfactants mixed with 0.03% sodium dodecylbenzene sulfonate and 0.1% Triton X-100 were used for spontaneous imbibition,attaining an oil recovery of up to 45%,which was 21.6% higher than that of single-surfactant imbibition. It was established that the synergistic mechanism depends on the wettability alteration of nonionic surfactant facilitating the spontaneous imbibition,while the anion accelerates oil removal from the core by continuously encasing oil droplets in the aqueous phase. This paper provides a theoretical basis for the imbibition development of weakly hydrophilic tight sandstone with high-salinity formation water.

Water content and distribution have important impacts on gas production in water-bearing tight gas reservoirs. However, due to the structural and chemical heterogeneity of tight reservoirs, the water phase exists in various states, which has complicated the analyses of the effects of water characteristics on tight gas production performance. In this work, the water phase is distinguished from immobile to mobile states and the term of constrained water saturation is proposed. It is established that water can flow when the driving pressure difference is larger than the critical driving pressure difference. A new theoretical model of threshold pressure gradient is derived to incorporate the influences of constrained water saturation and permeability. On this basis, a new prediction model considering the varied threshold pressure gradient is obtained, and the result indicates that when threshold pressure gradient is constant, the real gas production capacity of the reservoir will be weakened. Meanwhile, a dynamic supply boundary model is presented, which indicates that the permeability has a strong influence on the dynamic supply boundary, whereas the impact of initial water saturation is negligible. These findings provide insights into the understanding of the effects of water state and saturation on the threshold pressure gradient and gas production rate in tight gas reservoirs. Furthermore, this study provides useful guidance on the prediction of field-scale gas production.

Gravity can reduce the instability of the gas-oil contact that is caused by gas channeling in locations with low flow resistance, such as high-permeability layers, macropores, and fractures during the gas-assisted gravity drainage process. Herein, the microscopic forces during the gas-assisted gravity drainage process were analyzed and combined with the capillary model to study the occurrence boundary of gas-assisted gravity drainage process, and the characteristics of the gas-oil contact in the gas-assisted gravity drainage process was discussed. The results show that free gravity drainage occurs only in pores where a certain height of the oil column and pore radius are reached. Furthermore, the lower the oil-gas interface migration rate, the easier free gravity drainage occurs. In other scenarios, additional gas injection is required. During the gas-assisted gravity drainage process, the gas-oil contact moves down stably as a transition. The width of the transition zone and the available pore radius are related to the gas-oil contact migration rate and the oil viscosity; the smaller the gas-oil contact migration rate and the lower the oil viscosity, the smaller pore throat can be involved in mobilization. Optimizing the gas injection rate and reducing the oil viscosity can delay the gas channeling maturity time, which is beneficial for the realization of the gas-assisted gravity drainage process. Finally, a method considering micropore heterogeneity is established for determining the critical gas injection rate, while the mainstream pore throat can be involved in mobilization and the gas-oil contact can be stabilized at the same time. The method of determining the critical gas injection rate can help researchers and reservoir engineers to better understand and implement the gas-assisted gravity drainage process.

In this paper, a mathematical model of Hele-Shaw flow was developed on the basis of the field equation of micropolar fluid. The motion equation of micropolar fluid was extended to flow in porous media, contributing to the mathematical model of the unsteady radial flow of micropolar fluid in an infinite reservoir. The relations between flow velocity, pressure gradient and flow rate were obtained by solving the mathematical model under fixed production internal boundary and fixed-pressure external boundary conditions. In addition, the effect of the physical properties of micropolar fluid on its flow was analyzed. The results indicated a significant dependence between the apparent permeability and physical properties of micropolar fluid, which clearly deviated from the Newtonian fluid. The results showed that, as the ratio of rotational viscous force to Newtonian viscous force in the micropolar parameter and the characteristic length of the micropolar metamaterial increase, the non-Newtonian characteristics of the fluid become gradually more significant. The non-Newtonian behavior of micropolar fluid consequently becomes unneglected, leading to a decreasing apparent permeability. Compared with a Newtonian fluid, a micropolar fluid causes obvious flow resistance, resulting in larger energy consumption and lower flow rate. This study can provide an academic reference for nonlinear rheology and the flow of heterogeneous fluids in the fields of petroleum engineering and biofluid flow.

Water-alternating-gas (WAG) injection is recommended as a means of improving gas mobility control. This paper describes a series of coreflood tests conducted to investigate the potential for continuous gas injection and WAG injection in ultra-high water-cut saline reservoirs. The mechanisms of immiscible water-alternating-nitrogen injection on residual oil distribution are analyzed, and pore-scale analysis is conducted. The effect of injection parameters on residual oil distribution and recovery efficiency is also evaluated. Coreflood results show that tertiary oil recovery efficiency is significantly higher using WAG injection than continuous gas injection during the ultra-high water-cut period. Pore-scale visualization illustrates the movement of gas through the waterflooded channels into the pore space previously occupied by water and residual oil, which then becomes trapped. Injected gas breaks the force balance of microscopic residual oil and reduces residual oil saturation. This mobilizes the displaced/collected residual oil into large waterfilled pores and blocks several water channels. WAG flooding can decrease free-gas saturation and increase trapped-gas saturation significantly, resulting in decreased relative permeabilities of gas and water. The experimental results indicate that appropriate WAG design parameters could enhance recovery by 15.62% when the injected pore volume of water and gas in the cycle is 0.3 PV at a gas/water injection ratio of 2:1. The results from this study will allow researchers and reservoir engineers to understand and implement immiscible WAG injection as an enhanced oil recovery method in ultra-high water-cut stage reservoirs.