The evaluation of carbonate cores is a complex task because of the inherent heterogeneities that occur at all length scales. Rock properties may be defined differently at different scales and this introduces a challenge in capturing the heterogeneity in a single rock volume. This research work studied whole core samples using multi-resolution imaging and advanced computations. The samples could not be directly measured by conventional techniques due to their fractured state and complex nature. The cores are Mid Cretaceous in age, derived from a giant oil field in the Middle East and are predominately composed of limestone with complex paragenetic history.
The core samples were first imaged by X-ray dual-energy CT in 3D at a resolution of 0.5mm/voxel. The whole core CT images revealed extreme heterogeneity along the sample lengths and showed varying distribution patterns of high and low-density textures. The selected plugs from those density textures were acquired to accurately represent the different flow phases in the whole core samples. The plugs were fully characterized by high-resolution X-ray CT images at 40 μm/voxel, thin-section photomicrographs, poroperm measurements and Mercury Injection Capillary Pressure (MICP). These analyses provided a detailed understanding of the geological and petrophysical variations within the different density textures in the whole core samples. Simultaneously, smaller-scale subsamples were obtained from the different porosity regions in the plugs and scanned at higher resolutions down to Nanoscale at 0.064 gm/voxel.
The measured plug porosity and permeability data provided accurate results in the low and high-density regions in the whole core samples. This data was then upscaled to the whole core images by populating the individual data in the different textures and solving for the Stokes equation using the Lattice Boltzmann simulation. The upscaling process accounted for the varying fractions of the flow units in the sample, their interaction and their effects on the overall whole core properties.
The dual-energy CT scans along with core visual inspection, thin-section photo-micrographs and mercury injection pore throat size distributions (PTSD), demonstrated that each density region had similar geological and fluid flow characteristics throughout the core intervals. The upscaled poroperm data for all the core intervals gave a linear trend with a clear increment of porosity and permeability as a function of the low-density phase in the core. The permeability KV/KH anisotropy ratios were digitally computed for all the core intervals and were found to vary from 0.44 up to 0.94, which reflects the relative presence and distribution of the high and low-density regions in the reservoir core samples.
The digital analyses of the data together with the effects of heterogeneity distributions in the core provided an improved understanding of the geological and petrophysical properties in these complex reservoir rocks that would not be possible by conventional methodologies. The analyses were carried out at the pore scale and the core scale, which would lead to more robust reservoir engineering applications and petrophysical modeling of such complex reservoirs.