fax 01-972-952-9435. Abstract Important hydrocarbon accumulations occur in platform carbonates of the Lower Cretaceous Kharaib (Barremian and Early Aptian) and Shuaiba (Aptian) formations (Upper Thamama Group) of Abu Dhabi. A new, sequence stratigraphy-keyed static (geological) model has been built for the Upper Thamama (Lower Cretaceous) Kharaib and Shuaiba formations. The Kharaib Formation contains two reservoir units (Lower Kharaib Reservoir Unit and Upper Kharaib Reservoir Unit). The overlying Shuaiba Formation is separated from the Kharaib Formation by the Upper Dense Zone (Hawar) and contains two reservoir units (Lower Shuaiba Reservoir Unit and Upper Shuaiba Reservoir Unit) only partly separated by dense intervals.Core and well-log data of a giant onshore oil field in Abu Dhabi, as well as outcrop data from Wadi Rahabah (Ras Al-Khaimah) were used to establish a sequence stratigraphic framework and a lithofacies scheme; applicable to all four reservoir units and the three dense zones.Six third-order composite sequences are composed of twenty-six fourth-order parasequence sets that form the basic building blocks of a new generation static model.On the basis of faunal content, texture, sedimentary structures, and lithologic composition, fourteen reservoir lithofacies and ten non-reservoir (dense) lithofacies are identified from core. Reservoir units range from lower ramp to shoal crest to near back shoal open platform environments.A new static (geological) model has been built to provide a more detailed reservoir description to the dynamic model to further optimize the field development plan.

A new sequence stratigraphic framework is proposed for the Lower Cretaceous Kharaib Formation (Barremian and Lowermost Aptian) of the United Arab Emirates. This framework is based on the integration of core and well-log data from Abu Dhabi oil fields with outcrop data from Wadi Rahabah, Ras Al-Khaimah (U.A.E.). The Kharaib Formation is part of the late transgressive sequence set of a second-order supersequence, built by two third-order composite sequences. Fourteen fourth-order parasequence sets build into two third-order composite sequences and show predominantly aggradational and progradational stacking patterns, typical of greenhouse cycles. On the basis of faunal content, texture, sedimentary structures, and lithologic composition, eleven reservoir lithofacies and eight non-reservoir "dense" lithofacies are identified from core. These same lithofacies are also identified in time-equivalent rock exposures studied in Wadi Rahabah. The analyzed lithofacies range from open platform, lower ramp to restricted platform subtidal to intertidal environments. Intensively bioturbated wackestone and packstone, and interbedded organic- and siliciclastic-rich limestone characterize the three so-called dense zones (Lower, Middle, and Upper Dense Zone). Locally, mud-cracks, blackened grains, and rootlets are observed. The two reservoir zones (Lower and Upper Kharaib Reservoir Unit) correspond to the late transgressive and, dominantly, highstand systems tracts characterized by parasequence sets that show shallowing-upward trends from open platform, burrowed skeletal wackestone to skeletal, peloidal packstone and algal, coated-grain grainstone/rudstone, and rudist, algal floatstone/rudstone. Well-developed Thalassinoides firmgrounds (Glossifungites surfaces) indicate temporary cessation in sedimentation and cap several parasequence sets and parasequences. Stylolitic intervals within the reservoir units predominantly correspond to major facies changes related to third-, fourth-, and fifth-order sequence boundaries, parasequence set boundaries, and parasequence boundaries. In outcrop, low-angle clinoforms that cannot be seen in core data are observed within the highstand systems tract of the upper third-order composite sequence (Upper Kharaib Reservoir Unit). Integration of subsurface and outcrop data leads to more insightful and realistic geological models of subsurface stratigraphy. Introduction Large hydrocarbon accumulations have been discovered and produced from platform carbonates of the Upper Thamama Kharaib Formation in Abu Dhabi1,2,3. The Kharaib Formation (Barremian and Lowermost Aptian) contains two reservoir units (Lower and Upper Kharaib Reservoir Unit) separated and encased by three zones of very low porosity and permeability, subsequently referred to as dense zones (Lower, Middle, and Upper Dense Zone). Thickness of the Upper Kharaib Reservoir Unit is between 150 and 170 feet, and thickness of the Lower Kharaib Reservoir Unit is about 80 feet. Highly permeable beds (several Darcy) that mainly consist of coated-grain grainstone and rudist floatstone/rudstone facies are recognized in Field-A (Fig. 1). Generally, reservoir quality (porosity and permeability) decreases from crest to flank across the structure. This is due to compaction and cementation caused by the interaction with formation water. Diagenetic patterns of Field-B, Field-C, and Field-D (Fig. 1) are significantly different to those observed in Field-A. Whereas Field-A displays very good petrophysical properties, only locally affected by minor early- and late-diagenetic events, the reservoir quality of Field-B, Field-C and Field-D is impacted negatively by early-diagenetic porosity-destructive calcite cementation. This early-diagenetic calcite cement prevented significant compaction but occludes much of the primary interparticle porosity of the grainstone facies.

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This paper presents the results of a reservoir characterization and modelling study based on reservoir rock typing (RRT) of Lower Cretaceous carbonate reservoirs in one of Abu Dhabi Onshore oil fields. The final goal is to obtain multiple realizations of 3D descriptions of the petrophysical properties, namely porosity and permeability, which match and are consistent with the underlying RRT scheme, at the grid block level. The RRT were described in all sections of the reservoir for all cored-wells. The established reservoir rock types were based on depositional facies sequences, diagenetic overprints and petrophysical properties, including pore throat size distribution, porosity and permeability. The model reveals that the vertical changes in the rock types are a function of depositional facies, while the lateral variation down structure across the same lithofacies unit are controlled mainly by diagenesis. Considering the limited number of cored wells compared to the total number of loged-wells, the characterization started by predicting both permeability and rock type at the non-cored wells. Permeability was predicted using a combination of regression analysis and geostatistics. The use of geostatistics not only has been usefull in capturing the high variability of permeability but also has ensured that the core data is fully honored at plug locations. Rock type was estimated at the non-cored well using discriminant analysis. Consistency checks were been applied to the results of both prediction to ensure consistency between properties and rock types. Non-consistent results were assigned as unestimated-points. A geological conceptual model, in the form of iso-rock type maps, was used to QC the results of the prediction at the non-cored well and as a tool in deriving soft information about the spatial relationship of the different rock types. The 3D descriptions of the properties were generated using a geostatistical technique. The technique not only honors the conditioning data and spatial relationship of each property, but also honors the local relationship between each property and the rock type. Additionally, some constraints derived from the diagenetic model were implemented in the modeling process to ensure that the model follows the geological conceptual model as much as possible. In transforming the well-log data into the model grid, appropriate scale-up methods and grid-block thickness were selected to ensure that reservoir heterogeneities are maintained. Multiple realizations of the properties were generated in order to capture and to quantify the intrinsic variability of the model. The results of this characterization study will be used for flow performance evaluation. Introduction Simplified models for describing reservoirs with complex geology are not able to adequately represent the reservoir heterogeneities and their impact on connectivity patterns and flow mechanisms. A critical step in the construction of reservoir simulation models is the description of the underlying reservoir geology. This is even more mandatory in the case of carbonate reservoirs, frequently characterized by an intensive diagenetic overprint of the original carbonates. This process frequently includes assessing the complex reservoir internal architecture reflected in the internal discontinuities within the lithological units, vertical and lateral variation of rock properties and similar heterogeneities within the reservoir layers. The state of the art technology in generating reservoir models is to start with proper characterization of the underlying geology. The result of the characterization should be used in generating the 3-D model. The challenge that needs to be considered from the start is how the model can replicate the reality, i.e., what is defined during the characterization process.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents the results of a reservoir characterization and modelling study based on reservoir rock typing (RRT) of Lower Cretaceous carbonate reservoirs in one of Abu Dhabi Onshore oil fields. The final goal is to obtain multiple realizations of 3D descriptions of the petrophysical properties, namely porosity and permeability, which match and are consistent with the underlying RRT scheme, at the grid block level. The RRT were described in all sections of the reservoir for all cored-wells.The established reservoir rock types were based on depositional facies sequences, diagenetic overprints and petrophysical properties, including pore throat size distribution, porosity and permeability. The model reveals that the vertical changes in the rock types are a function of depositional facies, while the lateral variation down structure across the same lithofacies unit are controlled mainly by diagenesis.Considering the limited number of cored wells compared to the total number of loged-wells, the characterization started by predicting both permeability and rock type at the non-cored wells. Permeability was predicted using a combination of regression analysis and geostatistics. The use of geostatistics not only has been usefull in capturing the high variability of permeability but also has ensured that the core data is fully honored at plug locations. Rock type was estimated at the non-cored well using discriminant analysis.Consistency checks were been applied to the results of both prediction to ensure consistency between properties and rock types. Non-consistent results were assigned as unestimated-points. A geological conceptual model, in the form of iso-rock type maps, was used to QC the results of the prediction at the non-cored well and as a tool in deriving soft information about the spatial relationship of the different rock types.The 3D descriptions of the properties were generated using a geostatistical technique. The technique not only honors the conditioning data and spatial relationship of each property, but also honors the local relationship between each property and the rock type. Additionally, some constraints derived from the diagenetic model were implemented in the modeling process to ensure that the model follows the geological conceptual model as much as possible. In transforming the well-log data into the model grid, appropriate scale-up methods and grid-block thickness were selected to ensure that reservoir heterogeneities are maintained. Multiple realizations of the properties were generated in order to capture and to quantify the intrinsic variability of the model. The results of this characterization study will be used for flow performance evaluation.