Prediction of reservoir rock quality and distribution of porosity and permeability are not only the most important parameters in oil exploration but also the ones with major uncertainties. Ingrain has developed a methodology to properly capture heterogeneities of the samples that NOC and IOC companies have sent to our digital rocks laboratory.
Acquiring core data from a well is expensive and most of the times oil companies face the challenge of coring representative intervals that provides relevant information for reservoir understanding and modeling. Moreover, the process of selecting core plugs that capture the reservoir heterogeneities is not trivial.
Traditional core plug analysis provides one set of measurements per sample (single point data). At Ingrain, the same core plug is investigated for heterogeneities prior to evaluating the rock properties.
The process presented in this paper includes sample preparation, imaging, image processing and property computations. The sample is subjected to a descending scale of x-ray CT imaging, along with physical sub-sampling of the core. The descending size of scanning leads to increased resolution of the three-dimensional digital core, keeping the sample volumes registered in place. The resulting digital rocks are segmented and the pore structure is determined on the x-ray CT grid system. The resulting three-dimensional pore structure is used as the input grid system for direct fluid dynamic computations. These computations yield porosity, absolute permeability, relative permeabilities, and capillary pressure. In this paper we focus only on porosity and permeabilities. We will present examples of this topological information, where a trend of properties, porosity vs. permeability, captures the forecasting of rock heterogeneities that can be used to improve well decisions and field management.