With immense potential to enhance oil recovery, CO₂ has been extensively used in the exploitation of unconventional tight oil reservoirs. Significant variations are observed to occur in the oil’s composition as well as in its physical properties after interacting with CO₂. To explore the impacts of oil properties on CO₂ extraction efficiency, two different types of crude oil (light oil and heavy oil) are used in CO₂ huff-n-puff experiments. Moreover, numerical simulation is implemented to quantitatively inspect the impacts of different influencing factors including production time, reservoir pressure and reservoir temperature on physical properties as well as on the oil composition variation of the crude oil. The findings of the experiments demonstrate that, whether for the light oil sample or for the heavy oil sample, hydrocarbon distribution becomes lighter after interacting with CO₂ compared with the original state. In addition, it is also discovered that the hydrocarbon distribution variation is more significant for the light oil sample. The findings of the numerical simulation suggest that production time, reservoir pressure and reservoir temperature have significant impacts on the produced oil composition and properties. The hydrocarbon distribution of the oil becomes lighter with the increasing of production time and formation pressure, while it becomes heavier with the increasing of reservoir temperature. At the very beginning of the oil production, the properties of the produced oil are worsened. Compared with the original state, the oil density and viscosity are 25.7% and 200% higher, respectively. It is suggested that viscosity reducers are added into the well to improve the oil properties in this period. With the continuing of the oil production, the oil properties are continuously promoted. At the end of the simulation time, the oil density and viscosity are 3.5% and 15.1% lower compared with the original oil, respectively. This paper has great significance for the implementation of CO₂ huff-n-puff in tight oil reservoirs.

Gas injection is a potential proven enhanced oil recovery technique due to the difficulty of injecting water in the low permeability reservoir. In the process of gas flooding, there is mass transfer between fracture-matrix, which is called diffusion due to the fluid velocity difference in matrix and fractures. In the complex fracture network formed by hydraulic fracturing in the low permeability formation, this mass transfer is widely existed. However, it is often neglected in the past studies about optimization design of gas flooding. In this paper, embedded discrete fracture model (EDFM) using vectorization programming is built which is easy to obtain pressure gradient and velocity to characterize dispersion caused by velocity difference between matrix and fracture. And the EDFM is used to simulate the gas flooding for a typical well, which is in good agreement with Eclipse verified the accuracy of the model. Through a series of comparisons, the influences of different fracture network mode, matrix permeability, dispersion and gas injection rate on gas flooding are analyzed and the well performance is comprehensively evaluated considering the fracture network and the dispersion in the gas flooding.

There is a problem of a rapid decline in production caused by the repeated heating of the near-wellbore zone during steam stimulation. Finding a suitable foam system to expand the area of the steam chamber and slow down the rapid production of hot water during the recovery process can effectively improve the effect of steam stimulation. In this paper, CGS foam was prepared with high-temperature-resistant surfactant GD, graphite particles, and clay particles. Through the study of foam properties, it was found that with the addition of particles, the strength of the foam’s liquid film, half-life time, and temperature resistance was greatly improved. The appropriate permeability of the CGS foam and the movement characteristics of it in formations with different permeabilities were studied through a plugging experiment with a sand pack. The plugging performances of the GD foam, CGS foam, and pure particles in a simulated reservoir were compared. The development of the steam cavity during the steam stimulation process and the influence of injecting GD foam and CGS foam on the flow in the simulated reservoir were studied through a two-dimensional visualization model. The temperature resistance and stability of the CGS foam were better than those of GD foam in the simulated formation.

After offshore sandstone reservoirs enter the high-water-cut development stage, remaining oil gradually changes from a continuously movable state to a dispersed, isolated, and locally trapped state. Therefore, pore-scale dynamic characterization of remaining oil is important for clarifying its occurrence state and identifying potential targets for further recovery. In this study, natural cores from a typical offshore continental sandstone reservoir were used to conduct micro-computed tomography (micro-CT) scanning experiments at different waterflooding stages. Fine identification of the rock skeleton, water phase, and remaining oil, as well as segmentation of remaining-oil units, was achieved using U-Net semantic segmentation and three-dimensional digital image reconstruction. Multiple parameters were extracted, including volume, surface area, equivalent diameter, major-axis length, intermediate-axis width, minor-axis thickness, shape factor, and Euler number. Combined with manually labeled results of typical remaining-oil unit, a decision-tree method was used to establish classification criteria for remaining-oil occurrence states. The results showed that, with increasing pore volumes injected (PV), remaining oil gradually evolved from an initially large-scale and continuously connected state to a small-scale dispersed trapping. The surface area and volume of remaining oil continuously decreased. Meanwhile, the shape factor decreased, and the Euler number increased, indicating that the continuous oil phase was continuously cut and stripped into remaining-oil units with lower topological connectivity during waterflooding. At the early stage of waterflooding, clustered flow dominated in cores with different permeabilities, accounting for 96–99% of the remaining-oil volume percentage. Under high pore volumes injected (PV), the remaining oil volume percentage decreased to 30–65%, whereas the remaining oil volume percentage of columnar flow and droplet flow increased to 16–37% and 5–13%, respectively. These results indicated that waterflooding promoted the transformation of remaining oil from large-scale connected occurrence to locally trapped states under pore–throat constraint. Further comparison of cores with similar permeability but different pore structures showed that differences in pore–throat geometry, local connectivity, and pore–throat matching still significantly affected the fragmentation degree and spatial trapping mode of remaining oil. This study established a pore-scale method for dynamic identification, quantitative characterization, and type classification of microscopic remaining oil during long-term waterflooding in offshore sandstone reservoirs. The results provide a pore-scale basis for fine remaining-oil potential tapping in the high-water-cut stage.