Primary drainage capillary pressure data are essential input for static modelling of hydrocarbon reservoirs, estimate both oil and gas volumes in place and model saturation distribution. The behavior of the primary drainage curve is controlled by the pore throat size distribution, where a much wider pore throat size distribution is observed for heterogenous reservoirs. The objective of this paper is to determine capillary pressure modeling parameters for a wide range of geological textures of carbonate reservoirs covering different porosity and permeability ranges.
Representative core plugs were studied from different cretaceous carbonate reservoirs across the Middle East region. The data set available included laboratory-measured helium porosity, gas permeability, thin-section photomicrographs, and high-pressure mercury injection. The samples were grouped into 25 different rock types based on geological interpretation and capillary pressure data while honoring the porosity-permeability trends within identified textures (i.e., grainy, mixed, and muddy).
The capillary pressure data were matched using analytical equations with fitting model parameters (i.e., cwd and awd). The different rock types showed wide range of model parameters that could be linked to the different textures and the porosity-permeability distribution. Correlations between model parameters and rock properties (i.e., porosity, permeability, and texture) were derived, which could be used to predict capillary pressure curves from porosity and permeability in relatively less heterogeneous RRTs.
Rock types were successfully classified within different textures based on porosity, permeability, and capillarity. The capillary pressure modeling parameters provided more insight into the effects of geology on capillary pressure and saturation; and made it possible to quantify heterogeneity within different geological groups.