A super-giant carbonate field in Abu Dhabi has most of its remaining reserves in carbonate build-up and prograding basinmargin deposits of Lower Cretaceous age (Shuaiba Formation). To guide further field production, a sequence stratigraphic framework was developed based on integration of core, log and seismic data. This framework is the cornerstone for building a new reservoir model and provides the key for a better understanding of facies and flow unit continuity guiding present and future field production and performance.Approximately 730 wells, wireline logs and the latest core descriptions were integrated for this study. Another key element was the incorporation of 3D seismic data coupled with several iterations between well log and seismic picking. Detailed seismic interpretation led to the delineation of 3rd and 4th order sequences. The picking of higher order sequences was based on well data guided by the seismic surfaces. This study provides an excellent example of extracting maximum information from seismic and the full integration of geoscience and production data to provide a new 3D framework.The sequence framework uses a consistent nomenclature based on the Arabian Plate Standard Sequence framework for the Aptian (van Buchem et. al., 2010). The Shuaiba is subdivided into six 3rd order sequences (Apt 1, 2, 3,4a, 4b, and 5) which, based on stacking patterns, record a complete 2nd order cycle of Transgressive, Highstand, and Late Highstand systems tracts (Apt 1-4b). The Bab Member (Apt 5) and Nahr Umr Shale form the Lowstand to Transgressive systems tracts of the next Super-sequence.The third order Apt 1 sequence and the Apt 2 TST form the 2nd order transgressive systems tract, characterized by backstepping and creation of differential relief between the Shuaiba shelf and Bab intra-shelf basin. These sequences are dominated by Orbitolina and algal/microbial Lithocodium/Bacinella fossil associations.The Apt 2 HST and Apt 3 Sequence form the 2nd order early highstand systems tract during which the platform area aggraded and the topographic split into platform, slope and basin became most pronounced. Sediments are extremely heterogeneous and varying properties introduce significant problems in understanding fluid flow. During the regressive part of the Apt 3 sequence accommodation space was limited and deposition switched to progradation at the platform margin. The platform top is characterized by thin cycles of rudist floatstones/rudstones separated by thin cemented flooding and exposure horizons, whilst the platform margin received large quantities of rudstones, grain and packstones organized in clinoform sets. Clinoforms are separated by thin stylolitic cemented layers, which are transparent on seismic.The Second Order late highstand systems tract is composed of 3rd order cycles Apt 4a and Apt 4b. These are detached from the main buildup, which probably stayed largely exposed, and form strongly prograding slope margin wedges composed of alternating dense mudstones (TST) and grainstone/packstone sequences...

The Upper Kharaib Member of the Lower Barremian in Abu Dhabi onshore is represented by the Formation-B, which is separated from the overlying Shuaiba formation by 45 to 50 feet of dense Limestone of the Hawar formation. It is classified into B-Upper and B-Lower, comprising seven reservoir quality sub-zones (BI, BII, BIIIU, BIIIL, BIV, BV and BVI) separated by six stylolitic intervals. The average thickness for B-Lower is about 100 ft as compared to 60 ft in the upper zone. This study provides integrated sedimentological and diagenetical characteristics -in a field-scale -of the Formation-B in Abu Dhabi, UAE.A unified lithofacies scheme has been used to describe the Formation-B. These litho-facies have been grouped into eight genetically related lithofacies associations that reflect their corresponding deposition environments. The stacking of the lithofacies associations (inner ramp, mid-ramp and mid to outer ramp) define the broad 3rd order trends observed across the study field within the Formation-B, which have been compared to the regional sequence stratigraphic framework of Sharland et al. (2001).The lateral lithological variations occur at a higher order (i.e. 4th/5th order), most likely driven by autocyclic topographic/hydrodynamic variations, in addition to sea level changes; these will impart lateral reservoir heterogeneity. Within subzones BIV to BI, variations in lithofacies associations are observed due to the patchy nature of the higher energy inner ramp facies.The study concluded that the main controllers on reservoir quality distribution are texture and primary composition, as the matrix and grain ratio, together with allochems type, abundance, and size, define the genetically distinct characteristics of the lithofacies associations and provide the precursor fabric for subsequent diagenetic processes to occur. Cementation affects all the lithofacies; the morphology and pervasiveness of the crystals are dependent on primary and secondary pore space available for cementation. The key pore enhancing phases are dissolution events, mainly early and late dissolution enhancing micropores and enhancing/creating macropores, commonly partially or completely negating the effect of cementing phases. As the effects of the diagenetic overprint are linked to primary texture and composition, the distribution of the lithofacies and lithofacies associations will influence reservoir quality. The grainier lithofacies are more commonly seen to be influenced by pore-enhancing late dissolution phases, thus these facies host better reservoir quality. This is best developed in the upper portion of the Formation-B. The combined understanding of the sedimentological framework and the diagenetic overprint provides a robust tool for predicting the reservoir architecture.

The 3D architecture of flow units is a key parameter influencing production and recovery from oil reservoirs. Depositional facies and their 3D stacking patterns are commonly fundamental building blocks of flow units. Hence, the recognition of facies, and their placement in conceptual depositional environments is the basic requirement to establish 3 dimensional architectural models of reservoirs. In order to establish facies, facies stacking patterns and the 3D architecture of a super giant field contained in the Aptian in onshore Abu Dhabi , detailed sedimentological and petrographic core description have been carried out using about 13000 ft of core from a total of 49 cored wells. In total 27 facies have been established using fabric and bio content. They have been placed into conceptual depositional models following an evolving platform to basin topography during transgressive, early highstand and late highstand phases of carbonate platform development during the Aptian. This paper presents a comprehensive facies atlas that contains for each facies a detailed description of fabric and bio content, core and thin section pictures, petrophysical summaries and an interpretation of depositional environment. The large areal distribution of core coverage over more than 800 square km paired with the location of the reservoir transgressing platform interior to basinal settings ensures a comprehensive coverage of facies typical for most of the Aptian. The study developed an updated and unified facies scheme embedded in the existing interpretation of the depositional environments and high resolution sequence stratigraphy, and completed the core facies scheme definition which is understood as a fundamental criteria for the population of 3D static and dynamic model, in order to effectively enhance future reservoir development.

During the last decade, some problems have appeared and being affecting the oil production of the mature giant oil field such as: flow boundaries, by pass zones, fractures, etc. hence, the characterization of the reservoir by the integration of static and dynamic data acquired along the field life is required. The new generation of static model is justified in the need to involve the lessons learnt from the previous static/dynamic models with the incorporation of the recent studies and well data. The aim of this article is to integrate the structural seismic interpretation and results of pressure transient analysis obtained from well test, such as distance to potential flow boundaries, average permeability, among others, into the workflow of the new geological static model, through the validation with the conceptual geological understanding of the reservoir. Such workflow not only considers different sources for the reservoir characterization but also reduce the alternative solutions of the well test data to the best-fit solution for the integration. In a typical geological modeling workflow, structural framework is built first, based on the zones definition that include well information, well log data, structural seismic interpretation and the stratigraphic characterization that allow capturing the vertical heterogeneity. Subsequently, the sedimentary-stratigraphic architecture is used as main constrain together with geostatistical methods to distribute the petrophysical properties for each zones. The well test results independently are a punctual dynamic response of the reservoir in a portion of the time and within a certain tested area around the well. However, the integration with the conceptual geological model can resolve the uncertainty that alone cannot respond enable a more robust interpretation of main reservoir heterogeneities. The study proposes the inclusion of the well test data to support and validate, firstly the structural connectivity of the zones through the well test interpretation (validation of faults, dual porosity zones, dense zones, etc.), and secondly calibrate the permeability model with additional dataset than only from cores, which, even though derived from dynamic data, are incorporated in the static model workflow. Implementation of workflow allowed modeling of 48 zones with different petrophysical properties and 122 faults in the static model, which were ranked in three confidence categories. Faults observed by only seismic interpretation were ranked as low, faults calibrated by one of the 57 borehole images logs (BHI) were ranked as mid confidence, and finally, faults that were validated with best-fit result of well test, where interpretation suggest the presence of a boundary as fault and is consistent with the seismic and/or BHI interpretation, is ranked as the highest confidence, inasmuch as the fault is validated statically and dynamically.

Heterogeneous nature of the Cretaceous carbonate reservoirs in Abu Dhabi increases there complexity to attain efficient characterization and hence development. During depletion, reservoir pressure reduction results in unequal increase of vertical and horizontal effective stresses and thus an overall increase in the effective mean and shear stresses on the reservoir pore structure. At reservoir pressures below a critical value (obtained via laboratory testing or post failure field analysis), the reservoir compacts at accelerated rates. Compaction and its associated reduction in reservoir pore volume leads to rapid loss in permeability, generation of fines and wellbore stability issues (e.g., casing collapse). Assessing the magnitude of these changes require laboratory measurements of rock compressibility (grain, bulk and pore compressibilities), and concurrent evaluations of reduction of pore volume, porosity and permeability as a function of reservoir pressure needs to be appropriately simulated in-situ stress conditions. Poor appreciation of the rock compressibility mechanics and its robust dependence on stress path (e.g., hydrostatic- and/or uniaxial strain compression) in addition to depletion rate may result in substantial cost. The core intervals are selected to capture the lateral and vertical heterogeneity encountered in the studied reservoirs. The test program was designed to create a material model to capture the rock response to potential reservoir pressure changes. Single Stage Triaxial tests at multiple confining stresses were conducted to judge the shear failure. Tests recommended for evaluation and assessment of reservoir compaction are Uniaxial-strain compression (far-field compaction), triaxial compression (near wellbore), Hydrostatic (define the compaction cap) and constant stress-path. Additional tests were carried to characterize the poro-elastic response of reservoir rock and the stress-dependent permeability. A combined failure envelope (defining shear (dilatant) and compaction ("Cap") for compactable sediments) of the rock was generated by integrating the results from Single stage Triaxial tests (Shear failure envelope), hydrostatic compression tests and UPVC tests (Compaction failure envelope). For field applications, it is useful to provide a visualization of the pre-production-state in-situ stress conditions, and the possible stress path trajectories of the reservoir, as a function of reservoir depletion. Such a failure envelope was generated for all the different lithofacies encountered across the field. The characterized material model enables us to assess and predict the risk of shear/compaction deformation associated with the reservoir pressure changes (considering field stress path). Using this display, the level of depletion resulting in accelerated compaction can be identified through laboratory testing. The introduced workflow presents a comprehensive geomechanical characterization program for such complex carbonate reservoir. This utilizes a systematic approach to generate field wide understanding of rock response to depletion and injection. It can also act as a guide to address the compaction-based challenges faced in other reservoirs of Abu Dhabi.