A preliminary rock typing scheme for the Upper Jurassic was established on Arab reservoirs on a field offshore Abu Dhabi. This study was performed in order to assist in the reservoir modeling and ultimately in the accelerated development scheme of the field. The study is based on 165 samples from all the Arab reservoir levels (Arab A, B, C, D) in 6 wells. These samples were selected to cover all the reservoir facies and the range of porosity and permeability. All these samples have MICP data, thin section and porosity/permeability data. The objective was to identify the major rock types occurring in the Arab reservoirs from these samples.Rock types of the Arab Formation can be divided into 3 major rock type groups: Limestone, Dolomite, and Anhydrite. Limestones predominantly occur in the Arab D reservoirs, the dolomites in the Arab A, B, and C. Anhydrite occurs as non-reservoir, intraformational seal, and/or baffle between Arab, A, B, and C or is intercalated in these reservoirs.Six rock types were identified in the limestone reservoirs (L1 to L6) and five rock types were identified in the dolomite reservoirs (D1-D5). Various degree of overlap in reservoir properties do exist between some of these sub-groups. The dolomite rock types are easier to be classified into rock types compared to the limestone because of their uni-modal pore throat size distribution and well-defined capillary pressure curves. Reservoir quality is related to crystal shape, size, crystal-to-crystal contact, and dissolution.Limestones are much more complex and reservoir quality is controlled by mud content, grain size, sorting and diagenesis. Dissolution creating vuggy porosity can create high perm zones if the vugs are connected in both dolomites and limestones. Three limestone rock types show a pronounced dual-porosity system which is difficult to characterize with conventional rock typing methods.This work is being used to assist in the detailed characterization of the offshore field and in the ongoing field development.

TX 75083-3836, U.S.A., fax +1-972-952-9435. AbstractThis paper presents an integrated approach using the 3D seismic and well data to enhance our understanding of the lateral and/or vertical distribution of the Tar Mat. The study was carried out utilizing a recent stat-of-the-art, high resolution and high quality 3D ocean-bottom seismic dataset (OBC) acquired offshore Abu Dhabi and several wells with an excellent suite of logs, thousands of feets of core data and geochemical studies. A Model Based Acoustic Impedance Inversion was conducted following the 3D seismic reservoir mapping. A comprehensive porosity prediction analysis and validation were conducted for each well. The observation of the abrupt destruction of porosity in the well data associated with Tar Mat presence in the core led to the idea of computing the porosity derivative cube from the seismically predicted porosity cube. This significant and dramatic change in porosity associated with the Tar presence suggested that this porosity destruction might be visible in the seismically predicted porosity cube. The derivative of the porosity volume after post-stack Impedance inversion was generated to visualize the rate of changes in porosities. The high negative porosity derivative in a highly porous section may represent the top of a Tar mat. The high positive porosity derivative values also can be used to indicate Tar free developed porosity. Good match was found between the generated porosity derivative volume and the top tar from wells. Cross-plots between the seismic acoustic impedance and porosity for all wells (including Tar wells) suggest difficulty to distinguish between Tar and lithology change for porosities less than 12.5%. The lateral Tar distribution was found to be predictable utilizing this approach, through blind test well validation. The seismic Tar mat prediction on the porosity volume has provided new and important interpretation of the top of the Tar in the inter-well region and for the static model. Different Tar prediction schemes from seismic have been evaluated for further refinement. Differentiating tight rocks from the porosity plugged with tar remains ambiguous in the lower reservoir tight rocks. Therefore, a detailed sampling and geochemical analysis of the tar is being performed on the core to determine its base.

A new field in offshore Abu Dhabi is currently being developed by ADMA-OPCO by combining the production from six distinct carbonate reservoirs, each of which has different characteristics. The production and injection streams from all the reservoirs will be mixed and processed using common surface facilities (Offshore Super Complex).The development scheme was optimized based on the integration of the available geological, seismic, petrophysical, and dynamic reservoir data into six separate reservoir models. The optimized development plan was defined for each reservoir using its corresponding individual simulation model, where all reservoir models are compositional with similar pseudo-components.Because the field will be developed as a gas self-sufficient field with no gas export line, all the produced gas from the six reservoirs has to be managed within the field. After removing the fuel gas, part of the total produced gas is used for gas lift; whereas, the remaining gas is compressed and re-injected into reservoirs D, F, and G to ensure full gas balance.The facilities are shared by all reservoirs, so to further enhance field-development optimization modeling, especially with gas-recycling requirements, an integrated, multi-reservoir model with surface network was constructed. In this model, the six reservoirs were fully coupled with a single surface network, including wellhead towers, production/injection pipelines, and the Super Complex layout. This was accomplished by using a next-generation simulator that allows both surface and subsurface equations to be solved simultaneously.This paper addresses the steps followed and the challenges encountered and then summarizes the main outcomes. In addition, it provides a comparison with the results obtained from the single-reservoir models when run individually.The results obtained from the integrated model were slightly different when compared to those of the individual models because of the newly developed surface EOS model and the impact of the network on the individual reservoir's performance. The integrated reservoir model (IRM) proved its advantages, especially for gas recycling, by eliminating the previous iterative runs performed to achieve the field gas balance and by its ability to make the most effective usage of both water and gas plans to maximize recovery.

ADMA-OPCO is currently in progress of optimizing the development plans for several offshore undeveloped Abu Dhabi oil fields. A common basis in these developments is the incorporation of Intelligent Oil Field Concepts to improve recovery, safety and operating costs. This requires the application of several new technologies amongst which Smart Completions is seen as a challenging opportunity. These completions incorporate a combination of Permanent Downhole Gauges (PDHG), Inflow Control Devices (ICDs) and Multi Lateral Tie Back Systems (MLTBS) in various completion configurations. One of these reservoirs addressed in this paper is targeted to be developed via a 5-Spot water injection pattern. Due to the high heterogeneity of carbonate reservoirs, premature water breakthrough is a major concern. The planned well configuration will add significantly to the development Drilling CAPEX, hence understanding and quantifying the benefits of utilizing ICDs and MLTBS technology is required. Throughout this paper, the work flow used to assess the added values of ICDs and MLTBS has been presented based on sector models carefully extracted from the full field static model. These sector models target the key areas of the field where these smart wells are planned to be drilled. A history match process has been performed for model validation and to preserve the fine scale heterogeneity across the reservoirs. Approaches used for modeling these completion components using simulation software are discussed in this paper. The results obtained from this study have shown a positive impact of MLTBS whereas the ICDs implementation has shown no significant improvement in the ultimate recovery compared to the conventional open hole completion except the establishment of uniform flow distribution form heel to toe. Additionally, several different realizations have been undertaken to investigate the key uncertainties associated with such results and these realizations were compared to results obtained from a similar study performed on an adjacent field being developed by ADMA-OPCO. Lessons learnt were captured and summarized.

ADMA-OPCO is currently pursuing the development of several undeveloped structures offshore Abu Dhabi. These fields, some of which have been appraised over the last 30 years, are currently being evaluated and moved forward for full field development. As part of this development we are actively incorporating Intelligent Oilfield concepts into these development plans and this paper seeks to highlight some of the key considerations and assumptions being integrated into ADMA-OPCO’s philosophy for these developments. The next generation of oilfields is looking at these concepts to apply this advanced technology to: Enhance hydrocarbon recovery;Improve the safety for our Offshore Installations (by investigating new ways of working and opportunities to reduce the manning of these Operations);Reduce the Operating Costs (by improving the overall operating efficiency); It has been documented (Dickens et al. 2010) that by improving the down hole surveillance and control we may significantly enhance our ability to improve recovery in these large offshore fields. The challenges ADMA-OPCO faces offshore Abu Dhabi is that we are dealing with a high number of complex wells, to ensure adequate drainage and optimum flux rates, to enhance overall recoveries, from these difficult reservoir intervals. The optimal utilization of technology (for the applications of down hole monitoring and control) is complex as the number of wells and increasing complexity in well construction, is driving the drilling Capex higher. Current development plans in these fields show that a significant component of the field development capex is associated with the well construction costs, a significantly greater proportion of Capex than in conventional offshore developments. This is, due to the relatively lower facility costs associated with shallow water development in the Gulf. Hence optimization of well construction costs is a key component of successful delivery of the new fields. The rationalization of well complexity and organizational capability is an additional component in actively managing the increased risk associated with these non-traditional wells. Additionally we screened the systems, processes and infrastructure required to ensure optimal delivery of the real time monitoring capability and decision making capability that this technology can unlock. This paper will seek to share how ADMA-OPCO plans to move the field development concepts forward in the project life cycle and how we look to leverage world-wide learning in bringing this technology into offshore Abu Dhabi and details some of the challenges and opportunities that occur as we move forward with these concepts.