The Santa Barbara and Pirital fields are located in the North Monagas trend in the Eastern Venezuela Basin. Reservoirs in this trend are characterized by high initial temperature and pressure, and high initial production rates. A tar mat is present at the base of the oil column, acting as a barrier between the aquifers below and the oil-containing formations above. 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. The petrophysical characterization incorporated the analysis of the complex variations in pore and pore throat size that control initial and residual fluid distribution and fluid flow through the reservoirs. Conventional core porosity and permeability, mercury injection capillary pressure, relative permeability, and mineralogical data were used to characterize the reservoir 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. A methodology was developed to estimate flow behavior of the different flow units from the integration of rock, reservoir and fluid properties, analyzing the variables that affect production logs, reservoir conditions and the rock types determined. Production curves per foot of perforated interval, curves representing rock quality and a modification of the Vertical Stratigraphic Flow and Storage Diagram were used to cross-correlate different parameters in order to define relations between production rates and rock types, considering the effect of pressure differential between the borehole and the formation, as well as the characteristics of the fluids present in the formation. A clear relation was obtained between rock properties of the perforated zones and the production that they contribute to the total well influx. As expected, better relations were encountered for oil-producing than for gas/condensate-producing wells, since gas production is less dependent on rock quality. The determination of rock types from core data and the integration with production data for the definition of zones with similar flow characteristics is fundamental for appropriate reservoir characterization.