The high-temperature reservoir (105 °C) in the Liubei block of Jidong Oilfield, with severe longitudinal heterogeneity, has entered a high water-cut stage. After a preliminary profile control, the water management of the oilfield still faces serious water channeling problems. To strengthen water management, N₂ foam flooding combined with gel plugging for enhanced oil recovery was studied. In this work, considering a high-temperature reservoir of 105 °C, a composite foam system and starch graft gel system with high temperature resistance were screened out, and displacement experiments in one-dimensional heterogeneous cores were carried out. Through the three-dimensional experimental model and numerical model of a 5-spot well pattern, physical experiments and numerical simulations were carried out respectively to study water control and oil increase. The experimental results showed that the foam composite system had good temperature resistance up to 140 °C and oil resistance up to 50% oil saturation and was helpful to adjust the heterogeneous profile in a high temperature of 105 °C. The starch graft gel system had good injection performance, with a solution viscosity of 18.15 mPa·s, and its gel strength could effectively seal the high-permeability layer, with a gel viscosity of 34950.92 mPa·s. The displacement test results showed that after a preliminary implementation of N₂ foam flooding, N₂ foam flooding combined with gel plugging could still improve oil recovery by 5.26%. Compared with preliminary N₂ foam flooding, gel plugging could control the water channeling in the high-permeability zone near the production wells. The combination of foam and gel made N₂ foam flooding and subsequent waterflooding divert to flow mainly along the low-permeability layer, which was conducive to enhance water management and improve oil recovery. This method can be used as an effective technology to manage similar heterogeneous reservoirs.

Edge water and gas can be temporarily delayed with the assistance of stable N ₂ foam. The oil recovery enhanced by N ₂ -foam-assisted CO ₂ huff-n-puff was twice that by pure CO ₂ huff-n-puff.

Environmental awareness is receiving increasing attention in the petroleum industry, especially when associated with chemical agents applied in enhanced oil recovery (EOR) technology. The bio-based surfactant sodium cocoyl alaninate (SCA) is environmentally friendly and can be easily biodegraded, which makes it a promising alternative to traditional surfactants. Herein, the SCA surfactant is proposed as a foaming agent for enhanced oil recovery. Laboratory investigations on the surfactant concentration, foaming performance, microbubble characterization, interfacial tension, and foam-flooding of the traditional surfactants SDS and OP-10 have been conducted. In particular, the anti-salt abilities of these three surfactants have been studied, taking into consideration the reservoir conditions at Bohai Bay Basin, China. The results show that concentrations of 0.20 wt%, 0.20 wt% and 0.50 wt% for SCA, SDS and OP-10, respectively, can achieve optimum foaming ability and foaming stability under formation salinity conditions, and 0.20 wt% SCA achieved the best foaming ability and stability compared to 0.20 wt% SDS and 0.50 wt% OP-10. Sodium fatty acid groups and amino acid groups present in the SCA molecular structure have high surface activities under different salinity conditions, making SCA an excellent anti-salt surfactant for enhanced oil recovery. The microstructure analysis results showed that most of the SCA bubbles were smaller in size, with an average diameter of about 150 μm, and the distribution of SCA bubbles was more uniform, which can reduce the risk of foam coalescence and breakdown. The IFT value of the SCA/oil system was measured to be 0.157 mN m⁻¹ at 101.5 °C, which was the lowest. A lower IFT can make liquid molecules more evenly distributed on the surface, and enhance the elasticity of the foam film. Core-flooding experimental results showed that a 0.30 PV SCA foam and secondary waterflooding can enhance oil recovery by more than 15% after primary waterflooding, which can reduce the mobility ratio from 3.7711 to 1.0211. The more viscous SCA foam caused a greater flow resistance, and effectively reduced the successive water fingering, leading to a more stable driving process to fully displace the remaining oil within the porous media. The bio-based surfactant SCA proposed in this paper has the potential for application in enhanced oil recovery in similar high-salt oil reservoirs.

In view of the problems of low liquid production, a high proportion of high water cut wells, and poor development effect in the late stage of water flooding in the special sandstone reservoir of Niuquanhu "low permeability and medium viscosity crude oil", we carried out the research on hydrocarbon gas oil recovery and its influencing factors. First, the influence of different injected gas media on the physical properties of crude oil was analyzed. Second, the core displacement experiments of different gas injection media including CO₂, CH₄, and hydrocarbon gas were carried out by using the method of oil recovery comparison and optimization. Third, the indoor experimental study on the oil recovery of different influencing factors was carried out by using the method of controlling variables of influencing factors. Finally, the influence degree of different influencing factors on oil recovery was analyzed by a Spearman rank correlation coefficient analysis. The experimental results showed that the oil recovery of hydrocarbon gas is higher than that of CO₂ and CH₄, which were 57, 51, and 18% respectively. This is mainly because hydrocarbon gas is similar to the components of crude oil and is more easily dissolved in crude oil. The experimental results of influencing factors showed that the higher the content of C₂-C₄, the higher the oil recovery, and the content of C₂-C₄ will affect its dissolution with crude oil and its interaction with heavy component crude oil. The larger the permeability ratio, the lower the oil recovery, which was mainly due to the uneven distribution of injected gas in different regions. The higher the permeability, the lower the oil recovery, which was also due to the serious heterogeneity of the low permeability core of Niuquanhu; The results of Spearman rank correlation coefficient analysis based on different influencing factors and oil recovery showed that the order of influence of different factors on oil recovery was C₂-C₄ content > permeability ratio > permeability > back pressure > gas injection rate. In the development process of hydrocarbon gas injection, we should control the C₂-C₄ content, back pressure, and injection rate. The research in this study not only provides theoretical support for gas injection enhanced oil recovery technology in "low permeability and medium viscosity crude oil" reservoirs but also provides a new idea for the ranking of influencing factors.

Although gas flooding has been successfully applied for enhanced oil recovery throughout the world, most of its applications are conducted in low, ultralow, and tight oil reservoirs with light oil. Studies focused on a low-permeability reservoir with medium viscous oil are rarely reported, and there is little experience in the development of this type of reservoir for reference. Based on the special characteristics of low-permeability formation coupled with medium viscous oil in Niuquanhu Block, China, the gas-oil interactions of different gases are first evaluated through the pressure-volume-temperature (PVT) analysis. Then, the minimum miscibility pressure (MMP) of different gases is compared using slim tube experiments and a numerical simulation method. The oil recovery of different gas floodings is studied using core flooding experiments, and then the output oil compositions of different gas floodings are analyzed using a total hydrocarbon chromatograph. The PVT analysis results show that the interactions between hydrocarbons and medium viscous oil are the strongest compared with other gases. Under formation conditions, about 70 mol % hydrocarbons is dissolved in the medium viscous oil, leading to a 69% reduction of oil viscosity and a 48% increment of oil swelling, which is 1.19 and 1.35 times those of CO₂. The reduction of oil viscosity and increment of oil swelling of hydrocarbons are 1.64 and 2.02 times those of CH₄. And the reduction of oil viscosity and increment of oil swelling of hydrocarbons are 2.23 and 2.67 times those of N₂. Slim tube experiments show that the MMPs of hydrocarbon flooding, CO₂ flooding, CH₄ flooding, and N₂ flooding are 28.5, 36.8, 46.4, and 61.6 MPa, respectively. Therefore, compared with the other three types of gases, hydrocarbon flooding has the lowest MMP for low-permeability reservoirs with medium viscous oil. The errors between the MMPs of hydrocarbon flooding, CO₂ flooding, CH₄ flooding, and N₂ flooding obtained by the numerical simulation method and the results obtained by the slim tube experiment method are 0.71, 0.82, 0.87, and 0.98%, respectively. The numerical simulation results of the slim tube experiment show that the flooding pressure and oil recovery curves of different gas floodings all have inflection points. Under the existing condition, the inflection point pressure value is unchanged by changing the PV values of different gas injections. According to the results of a series of core flooding experiments and the analysis of the output oil compositions of different gas floodings, the oil recoveries of hydrocarbon flooding, CO₂ flooding, CH₄ flooding, and N₂ flooding are 57.02, 51.11, 36.88, and 21.35%, respectively, and the extraction ability of different gases to light hydrocarbon components is ranked as hydrocarbons > CO₂ > CH₄ > N₂. The findings revealed in this paper can provide technical support for gas flooding development in similar low-permeability reservoirs with medium viscous oil.