Characterization of Unconventional Reservoir Core at Multiple Scales

Abstract

Summary URTeC 1619973 Tight unconventional reservoirs have become an increasingly common target for hydrocarbon production. Exploitation of these resources requires a comprehensive reservoir description and characterization program to estimate reserves, identify properties which control production and account for fracturability. Multiscale imaging studies from whole core to the nanometer scale can aid in understanding the multiple contributions of heterogeneity, fracture density, pore types, pore connectivity, mineralogy and organic content to the petrophysical response and production characteristics. In this paper we describe examples of the application of a multiscale imaging and analysis method to characterize challenging unconventional reservoirs which incorporates: Geological rock typing and heterogeneity characterization at the core/plug scale (3D imaging and conventional descriptions); Mineralogy, primary grain structure and porosity/microporosity characterization at the pore scale via a range of 3D imaging technology (CT, micro-CT); SEM/SEM-EDS/FIBSEM analysis to reveal the nanoporous structure of important pore types (e.g, secondary porosity, microporous matrix, diagenetic minerals including clays); SEM and micro-CT analysis of wettability (applicable for oil reservoirs); Integration of image data to generate 3D model structures that honour the primary grain structure and accurately capture the nanoporous regions. The generation of integrated image-based microstructures provides the basis for the computation of key petrophysical and multiphase flow properties which impact on the storage capacity and production characteristics of the samples. Petrophysical properties are first calculated on various pore types at representative scales; these predictions are then upscaled to estimate the contributions to permeability, formation factor and elastic response of the key constituent phases (e.g., porosity and permeability associated with clays, slot-like pores, cement, and partially dissolved minerals (e.g. feldspars)) at the plug scale. Estimation of drainage relative permeability and capillary pressure from 3D image data and modelling are compared and predictions of flow properties derived. These predictions are compared/calibrated to high quality experimental data on the same or sister core material.