Horizontal wells with complicated fracture networks have become a key technical measure to improve the oil recovery of low-permeability and tight reservoirs in China. Spontaneous imbibition is regarded as the major oil recovery mechanism after fracturing. Due to the limitation of the observation scale, the traditional experimental methods cannot accurately describe multiphase fluid flow in the micro-/nanopore space of low-permeability and tight reservoirs, and the pore-scale oil recovery mechanism during spontaneous imbibition was not clearly understood. In this study, a novel mathematical model of oil replacement by spontaneous imbibition in fractured porous media is developed and then numerically solved using the phase-field method. By comparing the numerical results with the analytical solution of single-tube capillary-driven flow, which is widely described by the classical Lucas–Washburn equation, the accuracy of the proposed method is validated. The effects of rock wettability, oil–water viscosity ratio, interfacial tension, and fracture network on oil imbibition recovery are further explored. The results demonstrate that the pore-scale dynamic events of oil droplets including snap-off and coalescence can be well observed. The stronger the degree of water-wet and the lower the oil–water viscosity ratio, the higher the oil imbibition recovery. The oil–water interfacial tension exerts little impact on the oil imbibition recovery, while it can significantly affect the imbibition time. As the oil–water interfacial tension decreases, the imbibition time will become longer. The existence of a fracture network can enlarge the contact area of oil–water exchange, thus greatly improving the oil imbibition recovery during spontaneous imbibition. It is concluded that the pressure difference between fracture and matrix is of particular importance to achieve a high oil imbibition recovery in fractured porous media. The above understandings can provide a theoretical basis for the efficient development of similar reservoirs.

Polymer flooding is drawing lots of attention because of the technical maturity in some reservoirs. The first commercial polymer flooding in China was performed in the Daqing oilfield and is one of the largest applications in the world. Some laboratory tests from Daqing researchers in China showed that the viscoelasticity of high molecular weight polymers plays a significant role in increasing displacement efficiency. Hence, encouraged by the conventional field applications and new findings on the viscoelasticity effect of polymers on residual oil saturation (ROS), some high-concentration high-molecular-weight (HCHMW) polymer-flooding field tests have been conducted. Although some field tests were well-documented, subsequent progress was seldom reported. It was recently reported that HCHMW has a limited application in Daqing, which does not agree with observations from laboratory core flooding and early field tests. However, the cause of this discrepancy is unclear. Thus, a systematic summary of polymer-flooding mechanisms and field tests in China is necessary. This paper explained why HCHMW is not widely used when considering new understandings of polymer-flooding mechanisms. Different opinions on the viscoelasticity effect of polymers on ROS reduction were critically reviewed. Other mechanisms of polymer flooding, such as wettability change and gravity stability effect, were discussed with regard to widely reported laboratory tests, which were explained in terms of the viscoelasticity effects of polymers on ROS. Recent findings from Chinese field tests were also summarized. Salt-resistance polymers (SRPs) with good economic performance using produced water to prepare polymer solutions were very economically and environmentally promising. Notable progress in SRP flooding and new amphiphilic polymer field tests in China were summarized, and lessons learned were given. Formation blockage, represented by high injection pressure and produced productivity ability, was reported in several oil fields due to misunderstanding of polymers' injectivity. Although the influence of viscoelastic polymers on reservoir conditions is unknown, the injection of very viscous polymers to displace medium-to-high viscosity oils is not recommended. This is especially important for old wells that could cause damage. This paper clarified misleading notions on polymer-flooding implementations based on theory and practices in China.

Recently, as the demand for fossil and renewable energy continuously increases, enhancing oil recovery has become one of the key methods to meet the increased requirement. However, most of the oilfields are facing serious problems, including formation heterogeneity and low recovery factor. Therefore, further analysis is required to study the distribution of remaining oil and how to enhance oil recovery effectively. In this study, the core samples of different reservoir types were employed and characteristics of pore structure were measured by a high-pressure mercury porosimeter. The recovery factor and distribution of remaining oil with different reservoir types were determined by core flooding experiments and nuclear magnetic resonance tests. According to the results, the heterogeneity of pore structure becomes weaker as the permeability of the reservoir increases. The recovery during different periods improved as the core permeability increased. The distribution of remaining oil in different pore sizes has an obvious difference. The contribution of the recovery factor is highest in smallpores and mesopores for type II reservoir while is greatest in mesopores and macropores for type III reservoir. These results can provide theoretical and technical support for further enhancing oil recovery.