Calibrating micro-computed tomography data to permeability experiments and petrography – insights from Digital Rocks

Petrophysical measurements on core plugs integrated with petrographic information from thin-sections are established methods in reservoir quality assessment. X-ray micro-computed tomography (μCT) presents an opportunity to derive the internal structure of reservoir sandstones for digital fluid flow simulations, while si-multaneously assessing mineral distribution in 3D based on mineral densities. We compare the sin-gle-phase permeabilities obtained with fluid flow sim-ulations and experiments and discuss the anisotropic nature of the permeability tensor in both single- and two-phase flow. The results demonstrate a closer match for μCT porosity to petrophysical porosity com-pared to optical porosity, and an acceptable first order fit of the main mineralogical constituents. One-phase fluid flow simulations deliver results within 10–20 % of the laboratory measurements. Two-phase flow sim-ulations enable the assessment of relative permeabili-ties in rocks with water-sensitive minerals. However, μCT-based fluid flow simulations are computationally very demanding and time consuming due to the heter-ogeneous nature of natural sandstone samples, and require a tradeoff between resolution, representative volume, and cost. Rock composition reconstructed from μCT images can be used as a first-order approxi-mation for the composition of a sample, but is unable to confidently identify minerals that occur in minor quantities due to constraints of the chosen resolution. Thus, sandstone analyses by μCT cannot completely replace established methods.