A North Oman Field producing from two stacked Cretaceous reservoirs characterized by variation in inter-particle porosity along with variable vuggular and fractured secondary porosity system was studied. The objective was to build a reliable DPDP reservoir static model with scarcely available key data. An interdisciplinary approach utilizing available data, supplemented with analogs was used to implement a hierarchically linked reservoir characterization and modeling workflow for the purpose dynamic flow simulation studies. In the absence of core data, the NMR T2 distribution and derived permeability scaled to well tests mobility were correlated with borehole image features in a key well to define a rock typing scheme. The saturation height function was developed directly from the Sw and resistivity logs, by transforming and adjusting NMR T2 distribution to saturation height. In wells with only conventional logs, the SHF was used to back-calculate permeability within the transition zone. Electrical image logs in horizontal wells were used to build a high-resolution layering framework extrapolated inter wells to model highly conductive features (vugs and fractures). To address a relationship between secondary porosity selectively seen in thin dense layers, a BHI-based layering along horizontal wells was used to build the reservoir stratigraphic correlation to capture vertical flow barriers and high permeability vuggy layers. This approach used textural characteristics of rocks together with production data to capture mechanical stratigraphic boundaries and enabled fracture density estimation per mechanical layer. Use of hierarchical modeling workflow enabled the use of available BHI based rock texture, VCL from computed logs and acoustic impedance from inverted 3D seismic data to build 3D probability cubes of "mud-supported" and "grain-supported" rock textures. Conditioned to those 3D textural trend models, some seismic attributes were used as a guide to stochastically model the distribution of rock fabric based on the Lucia classification and the related inter-granular porosity. Subsequently the 3D distribution of Lucia-based Permeability and SW properties were also developed. Based on the assumption that fractures are developed within the perturbed stress field caused by the activity of the main pre-existing faults, a geomechanically-based process NFP workflow enabled us to build reservoir-scale fracture models. This workflow integrated seismic scale faults, and the distribution of fracture geometry and density from the wells coming from BHI logs, together with seismic discontinuity planes extracted from frequency-based filtering of seismic structural attributes. The tectonic model boundary conditions were estimated using 1D geomechanical models and analog data from neighboring fields. NFP-workflow generated fracture drivers; together with other fracture parameters, estimated from analog fields, neighboring outcrops and open literature, which were used to build a 3D multi-scale hybrid fracture model of the reservoir. The DPDP static reservoir model allowed dynamic history matching of the field with only global parameter adjustments, thus validating the property distribution from this static model.

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