Carbonate rocks are known for their heterogeneity and petrophysical complexity. This commonly leads to large uncertainties in reservoir models that are intended to predict fluid storage and fluid flow. In this article, focus is given to the characterization of pore systems at core-plug scale to provide improved models for permeability and saturation prediction. These methods fall under a wider rock-typing workflow.
We examine the use of mercury-air capillary pressure data for rock-type definition and for predicting saturation and permeability. We present new methods for modeling saturation in rocks with multimodal pore-throat size distributions. The methods bear similarity to those previously published but with some key differences, mainly by relating the capillary pressure data to the pore systems representative for a rock type. We also present a new method for relating permeability to pore-throat sizes that is more versatile, in that it can be employed for all types of pore-throat size distributions—unimodal or multimodal. We demonstrate that a normalized pore-throat radius parameter forms a straight line relationship with permeability over six orders of magnitude. It appears to be a fundamental property for all pore systems so far examined. The wider implication of the workflows presented is that they offer better integration between the methods used for saturation prediction and the methods used for permeability prediction, something that is desirable for all subsurface studies.