Pore-scale study of counter-current imbibition in strongly water-wet fractured porous media using lattice Boltzmann method

• Published in: Physics of fluids (1994) 2019-08, Vol.31 (8)
• Main Authors: Gu, Qingqing, Zhu, Lianhua, Zhang, Yonghao, Liu, Haihu
• Format: Article
• Language: English
• Subjects: Compressing; Configurations; Fluid dynamics; Fractured reservoirs; Fractures; Imbibition; Mathematical morphology; Oil recovery; Oil shale; Permeability; Physics; Porous media; Reservoirs; Rocks; Surface tension; Viscosity; Viscosity ratio; Water flooding; Water injection
• ISSN: 1070-6631; 1089-7666
• DOI: 10.1063/1.5099500

Oil recovery from naturally fractured reservoirs with low permeability rock remains a challenge. To provide a better understanding of spontaneous imbibition, a key oil recovery mechanism in the fractured reservoir rocks, a pore-scale computational study of the water imbibition into an artificially generated dual-permeability porous matrix with a fracture attached on top is conducted using a recently improved lattice Boltzmann color-gradient model. Several factors affecting the dynamic countercurrent imbibition processes and the resulting oil recovery have been analyzed, including the water injection velocity, the geometry configuration of the dual permeability zones, interfacial tension, the viscosity ratio of water to oil phases, and fracture spacing if there are multiple fractures. Depending on the water injection velocity and interfacial tension, three different imbibition regimes have been identified: the squeezing regime, the jetting regime, and the dripping regime, each with a distinctively different expelled oil morphology in the fracture. The geometry configuration of the high and low permeability zones affects the amount of oil that can be recovered by the countercurrent imbibition in a fracture-matrix system through transition of the different regimes. In the squeezing regime, which occurs at low water injection velocity, the build-up squeezing pressure upstream in the fracture enables more water to imbibe into the permeability zone closer to the fracture inlet thus increasing the oil recovery factor. A larger interfacial tension or a lower water-to-oil viscosity ratio is favorable for enhancing oil recovery, and new insights into the effect of the viscosity ratio are provided. Introducing an extra parallel fracture can effectively increase the oil recovery factor, and there is an optimal fracture spacing between the two adjacent horizontal fractures to maximize the oil recovery. These findings can aid the optimal design of water-injecting oil extraction in fractured rocks in reservoirs such as oil shale.