Seismic inversion for organic richness and fracture gradient in unconventional reservoirs: Eagle Ford Shale, Texas

Abstract

A method using Eagle Ford organic shale from Texas predicts key unconventional reservoir properties, total organic carbon (TOC), and fracture pressure gradient (FG). Applying petrophysical and rock-physics models from previous work to the available well-log data generates the required logs for calibration, i.e., shear sonic, TOC, organic porosity, and saturation. Prestack seismic data can be evaluated using synthetic forward modeling and can be conditioned further to improve AVO response. Simultaneous prestack inversion to derive acoustic-impedance (AI) and shear-impedance (SI) volumes can be run, and TOC can be derived from those volumes by linear interpolation. Fracture gradient (which also can be thought of as “frackability”) is related directly to Poisson's ratio and effective stress and can be estimated from elastic properties. The fracture gradient is related nonlinearly and inversely to TOC, i.e., assuming laterally and vertically homogeneous pore-pressure distribution inside the spatially limited block of the Eagle Ford Shale, higher TOC results in lower FG and hence better frackability.