Characterizing Foam-Based Frac Fluid Using Carreau Rheological Model to Investigate the Fracture Propagation and Proppant Transport in Eagle Ford Shale Formation

Abstract

AbstractIn-situ stresses and heterogeneity of the formation rock are the dominant factors that influence hydraulic fracturing process. The rheology of frac fluid also significantly affects hydraulic fracturing treatment regarding fracture propagation, proppant transport, formation property alteration, and flow back process. Non-Newtonian CO2 foams stabilized by nanoparticles has been recently studied as a promising frac fluid, which is advanced in less water contents, proppant placement, fast clean, and maintaining conductive channels. For the application of the new frac fluid for unconventional reservoir development, it is critical to investigate fracture propagation and proppant transport using CO2 foams.This study simulated hydraulic fracturing and proppant transport by viscous gas foams in a horizontal well perforated in Eagle Ford Shale formation of Zavala County, TX. A 3D numerical model was setup with heterogeneous reservoir properties using a commercial fracturing simulator - GOHFER. To represent formation heterogeneity, the rock mechanical properties were derived from well logs including Gamma Ray, Resistivity, Neutron Porosity, and Density Porosity logs, characterized by Young's modulus (3 × 106 ~ 6 × 106 psi), Biot constant (0.6 ~ 0.8), and Poisson's ratio (0.2 ~ 0.4). The flow behavior of CO2 foams stabilized by nanoparticles was characterized by Carreau rhelogy model based on the experimental data. During the pumping schedule for multistage fracturing process, the effects of variable injection rate (20 ~ 40 BPM), CO2 foams quality (50 ~ 80 %), incremental proppant distribution (0 ~ 5 PPA), and fluid leakoff were investigated.The results showed that a laterally un-even shape of fracture propagation profile was developed during multi-stage CO2 fracturing, which represents the reservoir heterogeneity with varying in-situ stress and poroelastic properties. The results also indicated that the rheology of frac fluid significantly influences the fractures propagation. As the viscosity of CO2 foams increases with variation of foam quality from 50% - 80%, fracture width increases but fracture length decreases. The fluid loss during fracturing was quantified by pressure dependent leakoff approach. For different CO2 foams quality (50% - 80%), fluid leakoff rate decreases with increasing the CO2 foam quality.This study provides a pioneering insight and improved fracture treatments design by non-Newtonian frac fluid - CO2 foams application with increased fracture conductivity and efficiency, which is vital for hydrocarbon exploitation from unconventional reservoirs.