Permeability and Microscopic Displacement Efficiency of M_1 Bimodal Pore Systems in Arab D Limestone

Abstract

Abstract Extensive and detailed studies of the pore systems of the Ghawar Arab D limestone have been captured in very large mercury injection capillary pressure data sets1–3 in which all data have been analyzed using Thomeer functions4–6. These data give new insight into the pore geometry dependence of the reservoir dynamical properties: permeability and imbibition oil relative permeability7 and yield ultimate recovery rock types with algorithms for rock type based reservoir simulation studies of ultimate recovery. New carbonate petrophysical concepts are established. The dominant subgroup of the examined carbonate limestone pore systems comprise the major Arab D reservoir section are denoted as an M_1 bimodal pore system3. The M_1 bimodal pore system consists of a macropore system (M), with a well defined and wide distribution of pore throat diameters and geometries, in conjunction with Type 1 microporosity with equally well defined and narrow distribution of pore throat diameters and geometries. This bimodal M_1 pore system results in a mixed wet reservoir condition in the bulk of the reservoir. The role played by the macro and micro pores of the M_1 pore system has been related to the reservoir dynamical properties: permeability and relative permeability7. This work demonstrates fundamentally new pore geometry based formulations for calculating permeability and imbibition oil relative permeability and therefore delineates the pore geometry based variation in microscopic displacement efficiency for variations within these systems. For these reservoir rocks, the appropriate pore geometrical parameters to perform ultimate recovery rock typing have been identified. This paper presents data and formulations for improved pore system based models of permeability and imbibition oil relative permeability in the M_1 bimodal pore system that reproduce measured laboratory data over a range of oil relative permeability from 1 to 0.0001 for seven waterflood composites. The relative permeability formulation uses two attributes of the pore system: permeability (already shown to be a function of pore geometrical parameters) and the volume of Type 1 microporosity alone. Both of these can be extracted from appropriate processing of appropriate well log data. These results show that shifts of the oil relative permeability curve to increasing water saturation (the right) commonly ascribed to wettability changes, result in this case from increasing the amount of Type 1 microporosity in the M_1 bimodal system which add an "ineffective" water saturation to the relative permeability water saturation axis. Introduction Extensive and detailed studies have been performed on the Arab D limestone pore systems in a major oil reservoir in Saudi Arabia. These studies have created connections between the three major languages of the subsurface: depositional geological facies, petrophysical rock types and reservoir static and dynamic properties1–7 as required for integrated reservoir characterization. These connections were made possible by a fundamentally significant observation regarding the limestone pore system geometries. It was observed that the spectrum of maximum pore throat diameters (Pd's) captured in this large mercury injection capillary pressure data set (MICP) could be characterized by four distinct Gaussian modes3 that have been termed "porositons" or "phitons" (figure 1).