AAPG Middle East Region Geoscience Technology Workshop

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An Integrated Approach towards Understanding Low Resistivity Pay in Cretaceous Natih Carbonates in the Fahud Salt Basin, North Oman: A Methodology from Natih-A Member


One of the main challenges in evaluation of microporous carbonate reservoirs is the high uncertainty in the interpretation of their petrophysical properties, in particular their permeability and saturation. This is even more challenging where no core is available and geological interpretations are based merely on wireline logs. Several examples from the Middle East have reported case studies that demonstrate carbonate reservoir intervals with an apparently low resistivity profile that produce dry oil. Those low resistivity pays could be discounted from volumetric calculation because of their assumed to be high water saturations as computed from resistivity logs using the conventional Archie’s equations. Such bypassed, yet accessible, pays might potentially unravel considerable volumes of hydrocarbon, particularly in brown fields where high well density captures spatial and temporal reservoir heterogeneity. Many rock types that are assigned for reservoir modelling in carbonate reservoirs are generated without an explicit, robust and generic workflow, mainly based on similarity of textural, depositional properties. Often, there is not a full consideration and integration of diagenetic modifications, which impact pore type distributions and therefore petrophysical properties. This new project addresses this challenge and aims to develop a novel integrated workflow to predict and identify potential low resistivity pay intervals in microporous carbonate reservoirs, using the Natih-A Member in the Fahud Salt Basin in North Oman. This will be an interdisciplinary study using geological and petrophysical data from core and wireline logs. It will provide and evaluate the impact of depositional and diagenetic processes on petrophysical properties, within the Cretaceous Natih-A carbonate reservoir by: • Characterising and quantifying the pore sizes, shapes and types of the primary and secondary porosity network to assess their controls on flow properties using detailed petrographic description by conventional petrographic microscope, scanning electron microscope, quantitative evaluation of minerals by scanning electron microscopy and x-ray computed tomography, • Determination of water saturation using mercury injection capillary pressure analysis and through differentiate variability in pore evolution and resultant size, shape and connectivity of pore system. Hence, pore topology will be related to capillary pressure and thereby determine saturation height functions and relative permeability curves for different, genetically related, rocks or pore types, and • Use saturation height functions to consider the viability of the Archie’s equation for determination of saturation from resistivity logs for different rocks or pore types and/or reservoir zones.