Reservoir: Petrophysical and Fluid Flow Properties of a Tight Carbonate Source Rock Using Digital Rock Analysis
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 increase permeability for the flow. To design an effective fracturing technique, it is necessary to 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 a Digital Rock Characterization workflow. The tight nature of the carbonate rocks prevented the use of conventional methods in measuring special core analysis (SCAL) data. 2D Scanning Electron Microscopy (SEM) and 3D Focused Ion Beam (FIB)-SEM analysis were studied to characterize the organic matter 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 related to identified rock fabrics and organic matter in the core. The organic matter was found to have an effect on the imbibition two-phase flow relative permeability and capillary pressure behavior and hysteresis trends among the analyzed samples. The data obtained from DRP provided information that can enhance the understanding of the pore systems and fluid flow properties in tight formations, which cannot be derived accurately using conventional methods.
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