Effect of fracture fluid flowback on shale microfractures using CT scanning

The field data of shale fracturing demonstrate that the flowback performance of fracturing fluid is different from that of conventional reservoirs, where the flowback rate of shale fracturing fluid is lower than that of conventional reservoirs. At the early stage of flowback, there is no single-phase flow of the liquid phase in shale, but rather a gas-water two-phase flow, such that the single-phase flow model for tight oil and gas reservoirs is not applicable. In this study, pores and microfractures are extracted based on the experimental results of computed tomography (CT) scanning, and a spatial model of microfractures is established. Then, the influence of rough microfracture surfaces on the flow is corrected using the modified cubic law, which was modified by introducing the average deviation of the microfracture height as a roughness factor to consider the influence of microfracture surface roughness. The flow in the fracture network is simulated using the modified cubic law and the lattice Boltzmann method (LBM). The results obtained demonstrate that most of the fracturing fluid is retained in the shale microfractures, which explains the low fracturing fluid flowback rate in shale hydraulic fracturing.