The application of digital rock models to petrography and fluid flow simulations in reservoir sandstones

Standard methods to characterize reservoir sandstone in the petroleum industry include microscopy-based petrography, as well as petrophysical measurements on core plugs. However, thin-section petrography cannot resolve 3D structures, and in case the sample contains water-soluble minerals two-phase flow measurements through a core plug will deliver inherently skewed results. X-ray micro-computed tomography (µCT) presents an opportunity to derive the internal structure of reservoir sandstones for digital fluid flow simulations while simultaneously assessing mineral distribution in 3D based on mineral densities. The results show an improved match between µCT porosity and petrophysical porosity compared to thin-section based porosity. Also, petrography derived from µCT densities shows an acceptable first order fit for the main petrographic categories quantified from thin-sections. Due to the high computational demand of µCT-based fluid flow simulations in heterogeneous sandstone samples, a tradeoff between resolution, representative volume, and cost is imperative. A good understanding of the encountered petrophysical and petrographic parameters is needed to adjust these variables on a case-by-case basis. In essence, mineralogy-reconstructions can be used as a first-order approximation, but are unable to confidently identify minerals that occur in minor quantities due to constraints of the chosen resolution. Therefore, µCT-based sandstone analytics are a supporting option for reservoir analyses.