Carbonate reservoir rocks present highly heterogeneous pore structure due to their growth by mineral precipitations and diagenetic alterations. Nevertheless, the resulting rock matrix properties, such as capillary pressure, porosity, and permeability, control the recoverable hydrocarbons storage, distribution, and flow mechanisms. In this paper we focus our efforts on the porous geometry scale dimensions controlling the absolute hydraulic permeability on complex carbonate matrix reservoirs from one oil-bearing pre-salt Aptian section at the ultra-deep waters of the Santos basin, Brazil. We introduce a multi-modal parametric Weibull function applied to reconstructing mercury injection capillary pressure (MICP) curves, by analytically solving a nonlinear least-squares inverse problem with the Levemberg-Marquardt algorithm. We stand on the theoretical model of the capillary bundle of tubes to propose petrophysical interpretations for the Multi-Weibull parameters and compute the MICP-based absolute hydraulic permeability through pore-dimension Kozeny-Carman equations. We then use the MICP-based permeability to test rock classification through Lucia's rock-fabric and Amaefule's flow zone indicator methods, further improving these classification schemes with depositional and diagenetic properties obtained from descriptions of petrographic thin sections. The Multi-Weibull function applied to the MICP inversion showed to be very adaptive to the different asymmetric shapes on the observed pore-throat distributions with high permo-porous quality, providing robust fits and, in consequence, accurately probing porous volume partitioning, detecting pore sizes at inflection points related to permeability, and the pore size at the entry pressure, a prominent parameter related to fluid saturation. The reservoir rock classification revealed that the rocks under analysis are well represented by general porosity-permeability trend lines of Lucias’ rock fabric numbers. Hydraulic flow units revealed strong correlations to characteristic pore-scale dimensions and to post-depositional diagenetic alterations, controlling the absolute hydraulic permeability behavior.
Primary petrophysical properties, such as matrix porosity, matrix permeability, wettability, capillary pressure, and initial fluid saturation control the main mechanisms of storage and flow of recoverable hydrocarbons, supporting the production volume, even to secondary extensive geological structures, such as open fractures and caves (Tiab and Donaldson, 2015). In this context, understanding pore-scale hydraulic efficiency of carbonate rock facies turns out to be one of the main tasks to accurately predict hydrocarbon reservoirs’ behavior. A great challenge to overcome since complex carbonate reservoir rocks are very unpredictable.