Rock Typing: A Key Approach for Petrophysical Characterization and Definition of Flow Units, Santa Barbara Field, Eastern Venezuela Basin

Abstract

Abstract The Santa Barbara Field is located in the North Monagas Area, Eastern Venezuela Basin. Reservoirs in the area are characterized by high initial temperature and pressure, and high initial production rates. The drive mechanism is solution gas drive and fluid expansion, with reservoir pressure declining rapidly. The hydrocarbon column varies from a gas-condensate cap at the top of the structure to heavy oil at the bottom. A detailed petrophysical model was necessary to optimize the secondary recovery processes implemented in the field. The petrophysical characterization incorporated the analysis of the complex variations in pore and pore throat geometry that control initial and residual fluid distribution and fluid flow through the reservoirs. Conventional porosity and permeability, mercury injection capillary pressure, relative permeability, and mineralogical data were used to characterize the reservoir pore systems into rock types having similar flow and storage capacity. Water Saturation, all of which is considered immobile, was found to be dependent on rock type, with pore throat being the dominant control on the flow characteristics of the reservoirs. Mercury injection capillary pressure data provided useful information about effective pore throat radii, which were semi-quantitatively related to several reservoir responses, such as permeability, porosity, irreducible water saturation, and a capillary pressure profile or pore throat type curve. Plots of pore throat obtained from empirical equations versus pore throat estimated from capillary pressure tests showed that the dominant interconnected pore system that controls flow in the reservoirs is best represented by the pore throat on a capillary pressure curve corresponding to 45% mercury saturation. Rock types were considered for the definition of injection intervals, and were also used to construct stratigraphic flow profiles, which were validated with production logs. Grouping similar rock types was found to be an excellent method for defining simulation layers. Rock type areal distribution maps were constructed to help delineate the best reservoir areas. The characterization of a reservoir into rock types in order to determine flow units effectively integrates geological, petrophysical and production data into descriptions of zones with similar flow characteristics, and is fundamental for the development of secondary recovery processes.