Digital core laboratory: Analysis of reservoir core fragments from 3D images

Subsets of a number of core plugs have been analysed using a high resolution X-ray micro-computed tomography (micro-CT) facility. The facility includes a system capable of acquiring 3D images made up of 2000 ³ voxels on core plugs up to 6 cm diameter with resolutions down to 2 µm. The cores analysed include a range of sandstone samples and one reservoir carbonate core. The cores exhibit a very broad range of pore and grain sizes, porosity, permeability and mineralogy. Computational results made directly on the digitized tomographic images are presented for the permeability and drainage capillary pressure across a range of φ. We show that data over a range of porosity can be computed from a single plug. Where available, we compare permeability and drainage capillary pressure computations to conventional laboratory measurements on the same core material. The results are in good agreement. The results demonstrate the potential to predict petrophysical properties from core material not suited for laboratory testing (e.g., sidewall or damaged core and drill cuttings) and the feasibility of combining digitized images with numerical calculations to predict properties and derive correlations for specific rock lithologies. The NMR relaxation response is computed on the digital images and the log mean relaxation time used to estimate the length scales associated with NMR response. We also directly measure sizes based on the pore volume-to-surface-area ratio and critical channel diameters associated with mercury porosimetry measurements. Differences between the resultant length scales are discussed. Formation factor is also calculated on the images. Empirical correlations linking fluid permeability to Formation factor and to a number of pore size parameters based on 3D digitized images of sedimentary rock are presented. All correlations perform well, with permeability estimates based on the capillary pressure measurements being the most reliable. We discuss the extension of the methodology to a wider range of petrophysical properties. In particular the need to calibrate the simulated data to parallel laboratory core measurements. This development should lead to a more systematic study of the assumptions, interpretations and analysis methods commonly applied within industry and lead to better correlations between petrophysical properties and log measurements.