Integrated Workflow for Petrophysical Evaluation in Heterogeneous Carbonate Reservoirs

Abstract

Abstract The cretaceous carbonate reservoirs in South Iraq are long known for exhibiting highly varying properties within small sections of the reservoir, the interplay of rock texture and pore networks arising from depositional facies and diagenesis presents a persistent challenge in predicting inflow profiles. The complex reservoir heterogeneity introduces considerable uncertainty, complicating modeling efforts for oil production and water cut prediction. Traditional approaches like Archie's method struggle to precisely estimate water saturation, as the Archie exponents ‘m’ and ‘n’ lack clear correlations with mineralogy and porosity. Complex carbonate pore structures and wettability alteration further contribute to the variability in the Archie exponents. The conventional resistivity and porosity measurements often fall short of capturing variations in pore size and texture. To address this, advanced measurements, including borehole imaging and nuclear magnetic resonance, become indispensable for extracting information regarding distinct textural components, porosity partitions, and fluid saturations. This paper introduces a comprehensive workflow that seamlessly integrates standard log measurements, image logs, and NMR data to accurately assess and characterize porosity, permeability, and saturation in carbonate reservoirs that exhibit multiple pore systems comprising microporous grains separated by intergranular macroporosity and with vugs due to grain absence. The integration of NMR and image logs is facilitated through the Gaussian decomposition technique, which deconstructs total porosity into its constituent components (micro, macro, vuggy, etc.). Subsequently, the partitioning analysis is employed to determine permeability, fluid saturation (by pore partition), carbonate rock types, and capillary pressure. For permeability, the macro permeability equation is employed, utilizing the volume of macro porosity as an input parameter. Saturation per pore partition is calculated using Ramakrishnan-Bruggeman's effective medium model, both in the uninvaded and invaded zones. This method accounts for drainage (oil emplacement) and imbibition (water-based mud filtrate invasion) processes, respecting the apparent wettability of each pore system. Carbonate rock types are identified through a classification scheme aligning with Dunham classes and based on the proportions of the three pore partitions. The mean T2 distribution for each rock type is transformed into pseudo-capillary pressure and associated saturation height functions using an appropriate PC to T2 scaling factor. This holistic integration of measurements enables the characterization of carbonate reservoirs in such details that are needed to realistically model such reservoirs and predict the production within optimal tolerance. The study not only underscores the impact of carbonate heterogeneity on Cretaceous carbonate reservoir evaluation in Southern Iraq but also introduces a reliable, log-based interpretation workflow suitable to precisely assess complex porosity and permeability systems in the absence of core data.