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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The gas present in the Valhall overburden crest area interferes with the seismic data and obscures the fault detection (minor faults). Spatially resolving fractures and fracture network is essential for subsurface understanding and future well placement in this field, and it is a critical input to the dynamic reservoir model. Additionally, mapping the fracture network in poor permeable reservoir formation beyond the wellbore is crucial to identify completion intervals to maximize productivity/injectivity, and hence field value. The well 2/8-F-18 A was drilled on the crest of the Valhall field as a pilot water injector in Lower Hod formation, where core and data analysis formed the foundation for a future potential 11 well development. The well is placed in the southern section of the Valhall crest, and no major faults or strong amplitude features were mapped out in the overburden via surface seismic before drilling. In this case study, an integrated workflow is proposed and tested within the reservoir formation to identify “sweet” (permeable and fractured) zones beyond the wellbore. This is achieved using borehole acoustic data combined with image and ultrasonic imaging to characterize fracture networks beyond the borehole wall. The sonic imaging workflow identifies reflection events from fractures and faults and provides the true dip, azimuth, and location in 3-dimensions. This data is complemented by nuclear magnetic resonance (NMR), dielectric and spectroscopy data to understand reservoir petrophysics. NMR-derived permeability has also been evaluated for identifying high permeable zone in this formation, which primarily focuses on intergranular permeability of the formation a few inches away from the borehole wall. Reservoir textural heterogeneity and fractures beyond the wellbore wall make this method difficult to estimate or enhance the effective permeability estimate. The baseline assumption for the NMR permeability estimation is also not valid in Hod formation; the Timur and SDR equation needs significant change to match core permeability. Hence, the primary aim is to identify a fracture network that will help support water injection and maximize hydrocarbons production through them. The goal is to establish a workflow from the learnings of this study, performed on the pilot well, validate its findings with the near-field data (core, imaging, and ultrasonic), and optimize it if needed (described in the methodology section). The developed workflow is then intended to be used to optimize the placement of future wells. The results achieved from the integrated workflow identified a key fault and mapped it approximately 23 meters away on each side of the borehole. It also captures acoustic anomalies (high amplitudes), validated based on near-field data, resulting from a fracture network potentially filled with hydrocarbons. The final results show the sub-seismic resolution of the fracture and fault network not visible on surface seismic due to the gas cloud above the reservoir and frequency effect on the surface seismic when compared to borehole sonic data. Evidently enhancing the blurred surface image, which helps enhance the structural and dynamic model of the reservoir.

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