The evaluation of shale is complicated by the structurally heterogeneous nature of fine-grained strata and their intricate pore networks, which are interdependent on many geologic factors including total organic carbon (TOC) content, mineralogy, maturity and grain-size. The ultra-low permeability of the shale rock requires massive hydraulic fracturing to enhance connectivity and thus permeability for the flow. To design an effective fracturing technique, however, one must have a good understanding of the reservoir characteristics and fluid flow properties at multiple scales. In this work, representative core plug samples from a tight carbonate source rock in the Middle East were characterized at the core and pore scale levels using Digital Rock Physics (DRP). The tight nature of those carbonate rocks hindered the use of conventional methods in measuring special core analysis (SCAL) data. Two-dimensional Scanning Electron Microscopy (SEM) and three-dimensional Focused Ion Beam (FIB)-SEM analysis were studied to characterize the kerogen content in the samples together with (organic and inorganic) porosity and matrix permeability. The FIB-SEM images in 3D were also used to determine petrophysical and fluid flow (SCAL) properties in primary drainage and imbibition modes. A clear trend was observed between porosity and permeability in relation with identified facies and organic matter in the core. Kerogen was found to have direct effect on the imbibition two-phase flow relative permeability and capillary pressure behavior and hysteresis trends among the analyzed samples. The obtained data from DRP provided information that can enhance our understanding of the pore systems and fluid flow properties in such tight formations, which may not be derived accurately using conventional methods.
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