Defining hydraulic properties of carbonate reservoirs has long been a longstanding debate and challenge due to its heterogeneity as a result of deposition and impact of diagenesis. The flow unit identification becomes non-trivial when the reservoirs are affected by extensive diagenesis, which results in a complex pore-size distribution. This condition makes standard logging suits inadequate. Therefore, advanced logs interpretation (NMR) with the integration of geological understanding, core and dynamic data are essential to derive a robust flow characterization. A comprehensive evaluation on multi wells that link different aspects controlling permeability has been carried out. The study comprised three integrated steps. The first step involved detailed diagenesis study of the reservoir where core analysis: petrographic examination, porosity-permeability measurements, pore throat distributions, and capillary pressure were introduced. The next step focused on the integration of full field NMR logs interpretation. Pore size distribution, porosity partition (macro, meso, micro), and free and bound fluid derived from 10 NMR logs were used across the reservoir section. The final step was to build the link between the pore connectivity obtained from NMR to diagenesis. Dynamic data such as production performance were then used to validate the integrated model. The result of the study reveals that diagenetic processes particularly dolomitization and grains dissolution have produced pore architecture that can be linked to NMR. This approach has a significant impact on the reservoir flow behavior, and has hence become a strong reference to find the sweet spot for the next drilling targets, which can lead to a proper flow characterization, better understanding of well production performance and dynamic reservoir description. Introduction Carbonate reservoirs are strongly heterogeneous in terms of porosity and permeability from the time of their deposition owing to rapid changes in depositional facies, and hence sediment texture. Diagenetic alterations (cementation, compaction, dissolution, micritization, neomorphism, and dolomitization) impose further and profound impact on modification to depositional porosity and permeability, and hence on final quality of carbonate reservoirs (Tucker, 2001; Wierzbicki et al., 2006; Morad et al., 2012). Diagenetic alterations are controlled by a complex array of inter-related parameters, which include depositional facies, mineralogy (aragonite, high-Mg calcite, and low-Mg calcite), changes in relative sea level, and structural deformation (Morad et al., 2000, 2012; Moore, 2005). The Simsima Formation, which is a major oil producing reservoir in the onshore field (Abu Dhabi, United Arab Emirates), has heterogeneous quality related to depositional and diagenetic processes (Badr and Ayoub, 1989). The Simsima reservoir is subdivided into three units (Upper, Middle, and Lower) on the basis of variations in petrophysical characteristics and depositional environments.

An important carbonate oil field, located onshore Abu Dhabi, has been producing from the Upper Cretaceous (Maastrichtian) Simsima Formation since 1983. To optimize and increase production of the field, seismic and high-resolution sequence stratigraphy was integrated by tying fourth-order, high-frequency sequences identified from core to 3-D seismic data. To establish the sequence stratigraphic framework, a new detailed sedimentological and high-resolution sequence stratigraphy study had been carried out, integrating approximately 7,000 feet of core material, approximately 3,500 thin sections, and all available well-log data from 46 wells. Core description, together with semi-quantitative petrographic examination of thin sections, established a new depositional model for the Simsima Formation. Sixteen lithofacies types (LF1 to LF16) representing a wide variety of depositional environments, ranging from upper ramp, rudist-bioclastic shoals to open marine mid to outer ramp mud-dominated settings. The newly developed, high-resolution sequence stratigraphic framework suggested that the Simsima Formation comprises one complete third-order composite sequence and the transgressive systems tract of an overlying second third-order composite sequence. These third-order composite sequences include seventeen high-frequencies, fourth-order sequences (HFS). HFS-1 to HFS-12 build the older third-order composite sequence, HFS-13 to HFS-17 form the transgressive system tract of the overlying, younger third-order composite sequence. 3-D seismic cross-sections show that fourth-order high-frequency sequences HFS-1 to HFS-6 of the older third-order composite sequence clearly show onlap on a pre-existing high (pre-Simsima unconformity surface), whereas the top part of the Simsima Formation (high-frequency sequences HFS-13 to HFS-17) show various degree of erosion. The established high-resolution sequence stratigraphic framework provides the layering scheme for the next generation Simsima 3-D static model, which will be used as input for the reservoir flow (dynamic) model. Introduction Large oil accumulations have been discovered and produced from the Upper Cretaceous (Maastrichtian) Simsima Formation in Abu Dhabi since 1983. The Simsima Formation was deposited on an actively growing paleo-high in shallow marine environment. It is capped by the basal shale member of the Umm Er Radhuma Formation and overlies the crest of partly eroded former structure of the Aruma Group. It ranges in thickness from 323 ft in the crest of the field structure to 628 ft in the flank. Recently, approximately 7,000 feet of core and 3,500 thin sections along with well-log data from 46 wells were studied. A total of sixteen lithofacies types were identified. As a result of the core study, seventeen high-resolution fourthorder sequences were established. They constitute a complete third-order composite sequence and the transgressive systems tract of an overlying second third-order composite sequence. The high-resolution sequence stratigraphy identified from cores was integrated with the 3-D seismic by tying the fourth-order sequences to the seismic data. An integrated layering scheme will be used for the next generation Simsima 3-D static model, which will be used as input for reservoir flow (dynamic) model.

Characterization of naturally fractured reservoirs is challenging because of variable properties and high heterogeneity. One of these examples is the complex fractured carbonate reservoir of Upper Cretaceous Maastrichtian age present in a field located in onshore of Abu Dhabi.A detailed study was conducted to accurately characterize and model fracture networks occurring in the reservoir, in order to control early water breakthrough problems caused by fracture connections to aquifer and resulting in reduced oil production and bypassed oil issues.The workflow involved a full interpretation of the seismic dataset and fault networks, concluding that faults are short and discontinuous, with frequency increasing with depth.A second step included a fracture network characterization using: Core, Borehole image, 3D seismic and dynamic data. Core description showed that reservoir is dominated by short diagenetic and styloliterelated fractures, with only rare tectonic fractures. Borehole image analysis confirmed core observations and concluded that fracturing is dominated by corridors related to faults, with thicknesses of 50 to 300 ft. No small-scale diffuse fracturing was detected. Seismic attributes were combined into fracture index maps to detect large-scale fractured zones at keys levels. Good relationship was found between the faults and lineaments from seismic and large fracture clusters seen on borehole image data.Dynamic analysis using production, pressure, PLT and well test data showed that production is mainly controlled by matrix. Moderate Kh and productivity enhancement was detected at proximity with corridors (around 100 m), and water production behavior was locally explained by corridors. No evidence for small-scale fracturing flow was found.Finally, a fracture model integrating all fracture characterization results was built and allowed computing equivalent fracture properties (fracture K in x, y, z, fracture porosity and matrix block sizes), in order to optimize new well location and trajectories for increased field production and delayed water breakthrough.

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