Fracture stimulation treatments of tight formations in the Cooper Basin can be associated with hydraulic fracture complexity that results in abnormally high treating pressures, low proppant placement and poor economic success. Pre-completion (image log and rock testing data) and post-completion data (fracture stimulation pressure decline plots) were reviewed in 13 treatment zones from the Cooper Basin. Rock strength, image log and stimulation data were available for seven of those zones.
From this analysis, a distinct relationship between rock properties (shear and tensile rock strength), geological weaknesses (natural fractures and other fabrics) and fracture stimulation complexity (net pressure, near-wellbore pressure loss and pressure-dependent leak-off) was observed. It is proposed that high in situ stress (Shmin≧0.8 psi ft−1; 18.1 MPa km−1), a large contrast in tensile strength between intact rock (T>1015 psi (7 MPa)) and pre-existing weaknesses in the reservoir (T∼0) promote the propagation of fracturing fluid along multiple fracture pathways, and thus abnormally high treating pressures, low proppant placement and poor economic success during fracture stimulation treatments in the Cooper Basin.
The methodology used to predict in situ stress and hydraulic fracture complexity herein presents a potential generic approach that can be used in similar basins where hydraulic fracture complexity is a problem or where conventional stimulation practices are unsuccessful.