Upscaled Gas and Water Relative Permeability from Pore and Core Scale Experimental Data Over Hydraulic Fracturing, Flowback and Online Production

Multiphase fluid flow in shale is known to be affected by micro-scale pore structure, wettability and complex fluid transport mechanisms. Investigation on the gas-water two-phase transport property during hydraulic fracturing, flowback and online production has practical implications in estimating hydraulic fracturing effect and development of shale gas. In this study, an upscaling method is proposed to derive core-scale gas-water two-phase relative permeability from the perspective of multiphase pore-scale simulation results and experimental data. First, inorganic matter (IOM)/organic matter (OM) pore netwok models are established in use of SEM images from Sichuan Basin, China. Gas/water absolute permeability on IOM/OM pore network model is calculated and gas-water two-phase imbibition (hydraulic fracturing) and drainage process (flowback-to-production) in IOM pore network model is simulated through invasion percolation theory. The comprehensive pore-scale gas-water relative permeability is modeled integrating, 1) real gas effect, critical property change, bulk gas flow demarcated by Knudsen number (Kn) in both IOM and OM, gas adsorption and surface diffusion in OM for gas phase; 2) boundary slip length and spatially varying viscosity for water phase; 3) a piston-like displacement during hydraulic fracturing, and a non-piston displacement during flowback-to-production in IOM incorporating corner flow for water and gas flow in the pore center. A core-scale model is generated by stochastically distributing IOM/OM patches and is proved by using our pressure pulse decay experiment data. A novel upscaling method is then proposed to calculate core-scale gas-water relative permeability by assembling pore-scale simulated permeabilities/relative permeability of IOM/OM patches over the 2D core-scale model during hydraulic fracturing and flowback-to-produciton. Next, the upscaling results are compared with analytical model, which exhibits a consistant pattern. Furthermore, the critical value of TOC content and intrinsic permeability ratio of OM to IOM on the variation of upscaled relative permeability is determined during different flow processes.