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A Reservoir Rock Typing (RRT) and Saturation modelling integrated study of the Lower Cretaceous Group reservoirs in Field X was conducted as part of required inputs into an ongoing FDP update. The results of this study allowed for a robust 3D modelling workflow that included saturation height modelling of the observed tilted oil water contact in the acquifer underlying three (3) of the major hydrocarbon bearing zones. The study intervals covered intervals that for the purpose of this paper will be called XH-4, XH-1, KX-2, XK-3 and XK-2 zones. Rock types were defined using core data integrated with geological descriptions and 3D distributed taking into consideration the depositional environments. Porosity, permeability and saturation property distribution was guided by the RT distribution. In total 44 wells in the field plus 4 nearby wells were incorporated in this study. This paper analyses the petrophysical, geological and static modelling workflows utilized. The RRT definition was based on the prediction of Self Organising Map (SOM) electrofacies which were classified using the petrophysical grouping obtained from lithofacies and depositional environment, permeability and MICP data. As a further step, the predicted RRT was optimised where the Archie saturation indicated that a different rock type was more likely. The analysis of virgin formation pressure data to understand the tilted OWC/FWL concept reveals that different wells have different absolute pressures. When the differences are mapped no regional trends were observed which makes a hydrodynamic origin of the tilted OWC/FWL less likely. Free water level (FWL) has been interpreted on well by well basis and mapped across the field for a better understanding of the variation. The pressure data are consistent with the scenario that the XH-4, XH-1 and KX-2 zones all share the same free water level for modelling purposes. The OWC is more or less flat in the central field area and is about 35 ft deeper in the eastern part of the structure. Although the difference in OWC could be abrupt (compartmentalisation), a gradual tilt seems to fit the data better. Furthermore, the ‘deepest oil observations’, which relate to paleo conditions, are deeper than present-day FWL in the east. All these observations would be consistent with a structural tilt towards the east. Similar trends were also observed from the FWL interpreted across key wells having formation pressure data. In terms of reservoir quality, the interval XK-3 has highest porosity and highest permeability. Also XH-1 and KX-2 contain good reservoir quality rocks. XH-4 is located above XH-1 and KX-2 and has relatively low quality matrix properties. It does contain low porosity (and hence brittle rocks) that can be expected to contain oil when fractured. The deeper XK-3 is probably disconnected from the underlying XK-2 which can be explained by the argillaceous interval between XK-3 and −2. XK-2 consists of thin reservoir intervals so that both Archie saturation estimates and the rock typing work carry significant uncertainty. The derived saturation height (SH) models utilise both a present-day and a paleo free water level per well. Each reservoir interval has its own SH-model based on SH-functions for each RRT. Implementation of all defined RRTs with associated SHFs was done to allow for highest resolution population of the geomodel, though a significant number of algorithms is required for this process. The RRT population of the static models was designed to be obtained from the combination of 3 distributed parameters: porosity, depositional environment, and reservoir quality by using the algorithms provided. Reservoir Quality is the driver most closely linked to diagenesis and local permeability variations.

Introduaction In a newly discovered field in the south east of Abu Dhabi, ten Thammama reservoirs were penetrated using a single well and how accurate an understanding of a reservoir and the uncertainties remaining can be assessed by a single well penetrating an accumulation of Hydrocarbon is a frequent question for companies planning to develop new, small reservoirs. The answer depends on how much data the single well got and the other information available about the reservoir and analogue reservoirs. When it comes to Modelling a reservoir that has only been pierced by one well, the assurance on the robustness of the available information is necessary in order to identify gaps and areas of uncertainty and then seek the means to minimize them. X-1 well drilled at the Crest of the structure and the location defined by utilizing leatest 3D seismic cube and the total depth 11500 ft RTKB. It was penetrated in the Lower Cretaceous sequence including ten reservoirs which are trapped by 4way dip closure. All the main reservoirs were tested in X-1 well and produced with an oil rate of 370 - 4,370 BOPD (30° - 32° API) An analytical "Lambda" Saturation Height Function was developed and implemented in order to overcome the absence of MICP data for initialization stage of Dynamic Modelling. Numerous choices made to develop a family of models that represents the range of reservoir possibilities. Uncertainty analysis including Analog Data from nearby fields utilized to rank the range of outcomes and prioritize obtaining additional information. This paper highlight a case study of a three onshore Abu Dhabi discovered structures addressing mitigations toward the challenges to draw a solid conclusion with single well modelling when it comes for development decision by Stakeholders at later stage. Further, the methodology as applied to the case study in this paper, allows identification of the range of outcomes and ranks the additional requirements, ranging from acquiring new Seismic data to drilling new wells, which guide for the next steps to a management decision to develop the reservoir or not.

Several challenges are associated with the characterization of organic rich unconventional plays, most significantly with the identification of sweet spots for optimum placement of horizontal wells, estimation of producible hydrocarbons and subsequent stimulation design. This paper presents the petrophysics and geomechanics integration approach from the X Formation and the important factors for the identification of sweet spots. The case study concentrates on the X Formation that consists of a succession of argillaceous limestone, mostly fine grained packstones and wackestones together with subordinate calcareous shales in the lower part. The complex carbonate lithology and fabric combined with low porosity and the requirement to evaluate total organic carbon presents a challenge to conventional logs and evaluation of them. Amid all the rock properties, the low permeability and productivity dictate the requirement to stimulate the wells effectively. Detailed integration of advanced and conventional log data, core data, mud logs and geomechanical analysis plays a critical role in the evaluation and development of these organic rich unconventional reservoirs. Extensive data gathering was done with wireline logging suite, which covered Resistivitiy/Density/Neutron/Spectral GR- Acoustic logs – Resistivity & Acoustic Images – Dielectric- NMR - Advanced Elemental Spectroscopy technologies and microfrac tests to characterize the hydrocarbon potential, sweet spots and in-situ stress contrast within the organic rich X Formation. The azimuthal and transverse acoustic anisotropies were obtained from X-dipole data to fully characterize the elastic properties of the formation. The static elastic properties were obtained using empirical core correlations as triaxial core tests were not available at the time of the study. The stress profile was calibrated against straddle packer microfrac tests to identify intervals with stress contrast for proper hydraulic fracturing interval selection. The integration of conventional and advanced logs enabled the accurate evaluation of total organic carbon (TOC), petrophysical volumes, and sweet spot selection. The advanced elemental spectroscopy data provided the mineralogy, amount of carbon presence in the rock, and consequently the associated organic carbon within the X Formation. The NMR reservoir characterization provided lithology independent total porosity. The difference between the NMR and density porosities provides additional information about organic matter. NMR data was utilized in this case study to identify and differentiate the organic matter and hydrocarbon presence within the X Formation. Acoustic and image logs provided the geomechanical properties that enable selection of the best intervals for microfrac stress measurement and proper fracture containment modeling. Geomechanical workflow allowed identification of intervals with a good stress contrast in X formation. The core data and stress measurements are recommended for the accurate calibration of the stress profiles and hydraulic fracture propagation modeling. The extensive data integration work presented in this single-well study within X Fomation, is a key factor for any organic rich unconventional reservoir characterization that integrated geology, petrophysics, mineralogy, and geomechanics for sweet spot identification within tight oil carbonate reservoirs.

Objectives / Scope This paper addresses the field development planning challenges of a green onshore South East Abu Dhabi oil field with limited production data. Tectonic movements have created strike slip faults dissecting the structure and uplifting the main body. Tilting of the flanks has resulted in the accumulation to leak some of its initial hydrocarbon and a rebalancing showing a titled FWL. A novel workflow was used to address the challenging reservoir physics including hydrocarbon below FWL. The paper takes a holistic approach in integrating multiple domains data such as Drilling, Petrophysics, Geology and Reservoir / Production Engineering. Methods, Procedures, Process An integrated approach was adopted to address the complexity and challenges of characterizing and modelling the field with hydrocarbon below FWL. Extensive range of data was collected to contribute to better understanding and evaluation of the field. The producibility of hydrocarbon below FWL have a significant impact on field development planning. The used workflow was specifically suitable to drive subsurface team right reservoir characterization: Improve fluid contacts understanding Explain the log responses The discrepancies between dynamic and static responses De-risk the volumetric uncertainties Results Following an extensive multi-disciplinary technical analysis of all available datasets, the most robust, accurate and reliable reservoir characterization, that can be seamlessly integrated into dynamic reservoir modelling phase. A systematic approach was adopted starting from core measurement and lab visits, drilling data such as mud logs, Petrophysical evaluation of multiple complex physics such as hydrocarbon presence below FWL, micro porous intervals, Micritic minerals and imbibition effect, geological regional understanding of faulted reservoirs, and dynamic data such as formation well tests. The study demonstrated that multi-domain integration played a key role in addressing the complex and challenging reservoir dynamics. Novel / Additive Information Large subsurface uncertainty combined with an extensive domain integration required cutting-edge reservoir de-risking and data gathering to provide the optimal reservoir characterization. These unique workflows can be readily used in similar green fields and will be described in full details in the paper.