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Abstract This work presents a new open access carbonate reservoir case study that uniquely considers the major uncertainties inherent to carbonate reservoirs using one of the most prolific aggradational parasequence carbonate formation set in the U.A.E; the Late Barremian Upper Kharaib Mb. as an analogue. The ensemble considers a range of interpretational scenarios and geomodelling techniques to capture the main components of its reservoir architectures, stratal geometries, facies, pore systems, diagenetic overprints and wettability variations across its platform-to-basin profile. Fully anonymized data from 43 wells across 22 fields in the Bab Basin, U.A.E from different geo-depositional positions and height above FWL’s (specified to capture multiple structural positions) within an area of 36,000 km was used. The data comprises of a full suite of open hole logs and core data which has been anonymized, rescaled, repositioned and structurally deformed; FWL’s were normalized and the entire model was placed in a unique coordinate system. Our petrophysical model captures the geological setting and reservoir heterogeneities of selected fields but now at a manageable scale. The novelty of this work has been to create semi-synthetic open access carbonate reservoir models which enable the geoscience and reservoir engineering community to analyse, study and test number of cases related to new numerical algorithms for reservoir characterisation, reservoir simulation, uncertainty quantification, robust optimization and machine learning. The value of this study is also to expose a model and a dataset to the reservoir simulation engineers so they can explore the impact of different fluid flow physics on sweep and recovery across multiple carbonate reservoir architectures with diverse lateral and vertical rock and fluid complexities – all of which can be history-matched against a ‘truth case’.
Zampetti, Valentina (Shell International B.V) | Perrotta, Sonia (Shell International B.V) | Chaari, Ghassen (Shell International B.V) | Krayenbuehl, Thomas (Shell International B.V) | Braun, Matthias (Shell International B.V) | Neves, Fernando (ADNOC) | Hu, Jialiang (ADNOC)
Abstract The Aptian Shuaiba Formation is among the most important reservoir units in the Middle East. Despite being extensively studied in recent years (Droste, 2016; Murris, 1980; Droste and van Steenwinkel, 2004; Yose et al., 2006;2010; van Buchem et al., 2002, 2010; Vahrenkamp, 1996), the interpretation of the Shuaiba depositional geometries, and specifically those associated with Shuaiba reservoirs, remains challenging in the seismic realm due to their intrinsic heterogeneity, variability and limited thickness. An integrated and iterative analysis including regional geology, well and seismic data was conducted to unravel the internal depositional geometries and associated reservoir properties for the Shuaiba Formation in the western region of UAE. In the study area, spatial distribution and geometry of the Shuaiba seismic facies was mapped in detail using full-stack reflectivity, discontinuity, curvature and spectral decomposition seismic attributes and further integrated with available well data and analogues. The Shuaiba Formation is expressed on seismic by mounded facies characterized by an irregular appearance, with discontinuous outline of sub-transparent reflectors, crossing reflectors and a larger thickness than the surrounding facies. Reflectors may locally coalesce and form mounded features up to 70 ms thick. The areas between mounds are characterised by sub-parallel to inclined reflections. The latter could be interpreted as clinoforms, prograding from the isolated nucleation areas to their deeper surroundings. The base of the mounds is located just above the top Thamama B/base Shuaiba reflector and the top coincides with the top Shuaiba. Well data suggest that these mounds consist usually of Bacinella/Lithocodium facies and rudists. The detailed 3D seismic interpretation of the Shuaiba reservoir geometries indicates a complex depositional architecture, which results in a variety of potential stratigraphic trap geometries and a heterogeneous reservoir property distribution. The proposed integrated workflow can therefore be used as a predictive tool to unravel further prospectivity in the Shuaiba Formation and in similar complex carbonate reservoirs, as well as to significantly improve reservoir property distribution prediction in static models.
Kundu, Ashish (Abu Dhabi Co For Onshore Petroleum Operations Ltd) | Voleti, Deepak Kumar (Abu Dhabi Co For Onshore Petroleum Operations Ltd) | Rebelle, Michel (Abu Dhabi Co For Onshore Petroleum Operations Ltd) | Al Housani, Habeeba Ali (Abu Dhabi Co For Onshore Petroleum Operations Ltd)
Abstract The studied lower Cretaceous carbonate ramp deposits are heterogeneous with pervasive diagenetic processes leading to complex pore network and rock texture. Before this study, field development was based on log based water saturation modeling. This saturation modeling was dependent on the hydraulic flow units and porosity classes, which was meant to be, but was not explicitly representative of the defined geologic facies. The assignment of the relative permeability data is also very challenging in the absence of proper Rock Type model. Often in carbonate reservoirs, there is no direct or linear relationship between Reservoir Rock Types (RRT), sedimentological facies assemblages and water saturation distribution across the field. Hence, accurate integration of the sedimentological, diagenetic, depositional environment information and petrophysical properties is essential in building a robust RRT model. This RRT model can then explain the rock-fluid interaction through a reliable saturation height model. In the first part, the paper illustrates the workflow which involves integrating lithofacies, depositional packages, degree of cementation, pore-type from sedimentology and relating resultant pore-typing to core porosity–permeability data. This workflow resulted in a strong reservoir rock typing scheme, which was key in building a robust saturation height model. Precisely, this was achieved by assigning "most-of lithofacies and diagenetic indicators" to each rock type defined. In the second part, a Variable Saturation Height Function (VSHF) was developed using mercury injection capillary pressure (MICP) data. The function was made variable with depth by bringing one or both of the reservoir parameters (Phi and K) into the equation. Most importantly, VSHF explicitly scans the lower and upper Sw boundary of a particular rock type and helps in removing the skewness in the Sw difference histogram between model and log Sw. One of the important steps in the workflow was to normalize the MICP data to log derived Sw values, provided the confidence on the Sw calculation from logs is high. After stress and closure correction, the normalization of the reservoir Pc data was achieved through an independent correction factor. Both of the workflows (rock typing and saturation height modeling) were built based on data from 30 cored wells. The workflows were tested on 15 cored wells and more than 600 non-cored wells. Rock type maps were found to be more correlatable with reservoir quality maps than lithofacies maps alone. This is a result of the diagenetic processes undergone by the rock during and after deposition modifying the original depositional controlled pore architecture. With this approach the water saturation distribution was more consistent with logs and core derived Sw data. The workflows shown in this paper are reliable and can be extended to other carbonate fields’reservoir characterization.
The aim of this study is to propose a stratigraphic and sedimentary framework though the integration of available sedimentary, diagenetic and petrophysical data, which will be utilized in the construction of a high resolution stratigraphic framework, as an input into comprehensive review and update of an existing model of heterogeneous carbonate reservoir in a mature field in Abu Dhabi, UAE. Depositional facies have been defined in cored wells, subsequently were associated taking into account the biologic and sedimentary processes in response of carbonate growing and sea level changes, allowing the identification of the main stratigraphic surfaces. Surfaces can extend the correlation along the field and define the model of facies that, with the evidence provided by cores, can recreate and predict the different regressive-transgressive cycles in high resolution which the carbonate platform were undergone during its evolution. Diagenetic evolution, interpreted through laboratory observations, was integrated with facies and petrophysical evaluation allowing the understanding of the spatial distribution of petrophysical properties within a heterogeneous reservoir and define a new set of facies which will be used in the generation of geological static model. Application of sequence stratigraphy methods in cores, and extended in logs allowed the identification of six depositional sequences, with thicknesses of 2 to 4 meters each, corresponding to the phases of carbonate platform growth. Within each depositional sequences, typical cycles were defined that support the understanding in the association of facies and their relationship during the deposition. The identification of sedimentological cycles not only genetically organizes the facies and predicts the stacking pattern, but also makes possible to find an excellent correspondence between cycles from lowstand system track intervals with good to excellent permeability values, and cycles from transgressive system track intervals with low permeabilities. Many of the sequence stratigraphy published articles driven for the most important reservoirs along the Arabian Plate, provide an excellent tool in the regional correlation. However, they are not enough to be used in the reservoir characterization in detail that is required during the development of the field neither as input data in the generation of geological static models that use the sedimentary trends as constrain to populate the petrophysical properties. 2 SPE-188875-MS
Strohmenger, Christian Johannes (Abu Dhabi Co. Onshore Oil Opn.) | Al-Dayyani, Taha (Abu Dhabi Co. Onshore Oil Opn.) | Clark, Andrew Brampton S. (Abu Dhabi Co. Onshore Oil Opn.) | Ghani, Ahmed A. (Abu Dhabi Co. Onshore Oil Opn.) | Hafez, Hafez H. (Abu Dhabi Co. Onshore Oil Opn.)
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. Introduction Large hydrocarbon accumulations have been discovered and produced from platform carbonates of the Upper Thamama Kharaib and Shuaiba formations in Abu Dhabi 1,2,3. The Kharaib Formation (Barremian and Early Aptian) contains two reservoir units (Lower Kharaib Reservoir Unit and Upper Kharaib Reservoir Unit) separated and encased by three zones of very low porosity and permeability, subsequently referred to as dense zones (Lower Dense Zone, Middle Dense Zone, 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 4,5. 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. Thickness of the Lower and Upper Shuaiba Reservoir Units is approximately 55 and 90 feet respectively 4,5. Generally, reservoir quality degrades from the structural crest to the flank of the field 6. This is due to compaction and cementation caused by the interaction of the carbonates with formation water during burial 4. A giant carbonate oilfield, located in Abu Dhabi, has been producing from Lower Cretaceous reservoirs since 1973. The current field development plan (FDP) is based on a reservoir model, which has evolved in stages, with input from many field and laboratory studies over the past 20 years 6,7,8. The most recent static model has been built incorporating the results from significant new core characterization and sequence stratigraphic studies (> 110 cored wells), in addition to a more thorough integration of geological, production, and 3D (and 4D) seismic data. Modeling such a large and active field presents real data management challenges. These challenges include the choice of geo-modeling software, accessing and maintaining the corporate database, and ensuring that all engineering and geosciences disciplines are able to easily contribute and use the final integrated model.