Objectives/Scope Recently Abu Dhabi National Oil Company has called Whitson (PERA), a world leading PVT modelling consultancy company, to develop a best practice methodology/tool to quantify the condensate liquid production originating from the gas cap that is produced through oil rim producers' wells. This practice is integrating simulation work with field measured data and provided for the first time a solution to an oil and gas industry challenge, which is causing a conflict of interest between shareholders especially when oil rim and the associated gas cap are belonging to different concessions. Methods, Procedures, Process The work has been done for a giant oil field with large gas cap (rich in condensate) where only the oil is being developed since the 1960s. Initially the production GOR was limited to RS, but in 2010 the development strategy changed, and the field was being produced at GOR higher than RS allowing free gas from Gas Cap (rich with condensate) to be produced with oil. The question then arised of how much condensate is being produced through the oil rim producers. The condensate allocation method makes use of all measured well test data (Qo, GOR and API) and compositional reservoir simulation results. The used EOS (equation of state) model has been tuned to all available laboratory PVT data. This method uses a history-matched, reservoir simulation model run with a "dual-EOS" that is constructed by duplicating the tuned EOS model into two identical EOS models - one for the initial gas cap, and the other one for the initial oil zone. The dual- EOS run gives identical performance to single EOS model run. The generated dual-EOS compositional wellstreams are adjusted (1) to honor exactly the historical well test GOR data for each well, and (2) to honor as best possible the historical well test APIs for each well. The resulting wellstream will honor exactly the simulation model oil rates of each well throughout history, exactly the measured well test GOR, and close-to-exact APIs for each well. The final altered well streams are processed through a 4-stage field separator, yielding the well total stock-tank oil and condensate volumes. Results, Observations, Conclusions Historical gas cap condensate volumes produced from wells completed in the oil rim has been achieved during the field history. This was made possible by using (1) well production test data (GORs and APIs), (2) results from a history-matched compositional model, (3) tracking of components originally found in gas cap and in oil rim, and (4) application of a tuned EOS model. The conclusion is that such an integrated approach will result in a consistent and quantitatively accurate volume of condensate production volumes. Novel/Additive Information An innovative quantitative approach to the accurate estimation of condensate volumes originating in the gas cap - but produced from wells completed in the oil rim zone - has been developed and validated and could be applied for other fields, in addition it is fully flexible for future enhancements if needed. This methodology will definitely save time and unnecessary discussion and will provide more consistent results that will lead to more consensus from different parties.

The objective of this paper is focused on presenting and highlighting the results of the first successful reservoir fluid characterization and sampling attempt in offshore Abu Dhabi and the added values to the assets operating in the highly heterogeneous Jurassic carbonate reservoirs with unknown formation water salinity values. The original formation water has a unique high salinity that got mixed overtime with the fresher injection water, so that the open hole log interpretation using Archie water saturation model becomes highly uncertain. Exaggerated oil saturations could be computed within the water zones around the oil-water contact. In addition to measuring the fluid mobility, the formation testers are being run to confirm the fluid type present in the reservoir by using pressure gradient plot or by fluid identification and sampling stations. The increasing cost and rig time optimization demands inspired the team to utilize the emerging formation sampling and testing while drilling at the first time in offshore Abu Dhabi to replace the conventional wireline/ drill pipe conveyed formation testers. This application proved to be an added value to gather the required reservoir data in a mature challenging field reducing the operational time, cost and associated risks. A water injection well is drilled across a highly heterogeneous, Jurassic carbonate reservoir offshore Abu Dhabi. A deviated pilot hole was drilled for formation evaluation and reservoir fluid assessment, and the plan was to continue with a horizontal drain into one of the sub-reservoirs (swept area) if confirmed water bearing. The logging while drilling formation sampling and pressure testing tool was run combined with the conventional open hole logs to minimize the formation exposure time, real time down-hole fluid analysis started very shortly after drilling to the bottom of the target reservoir, based on the rush open hole log interpretation. Different sensors, with different physics (namely; fluid viscosity, density, sound speed, optical refractive index, temperature, fluid mobility and compressibility) were used to characterize the fluid during the pump-out stations. Due to the minimized mud filtrate invasion effects, this operational sequence allowed the gathering of conclusive formation fluid samples with less pumping time and volume. This paper shows the operational planning, design and execution outlines, discusses the benefits of acquiring clean formation samples right after drilling compared to those acquired with the conventional conveyance techniques, and indicates the drawbacks and the limitations of this technology together with any window of improvement.

Severe Asphaltene deposition is encountered in some wells drilled in newly developed reservoirs of one of Abu Dhabi's giant offshore assets (Field AD), and for the first time, full well plugging with Asphaltene is experienced in the field. While successful curative clean up treatments are regularly made, the relatively high intervention frequency (once every month per well) has impeded the full-scale development of these reservoirs. This study shows how understanding the mechanism of Asphaltene stability/instability in field conditions can unlock the production of under-developed reservoirs (with hundred millions barrels of OIP) by anticipating and considering preventive measures during the design of new wells to limit Asphaltene deposition. In order to prevent the occurrence of Asphaltene deposition from reservoir formation to surface level, a Flow Assurance study was launched by the operating company with close support from the international partner. The objective was to determine the Asphaltene Deposition Phase Envelope (ADE) of the reservoir fluid by measuring onset pressures with Visual (High Pressure ‘HP’ Microscope) and Near Infrared Solid Detection System (SDS) as a function of 2 main variables: Different temperatures to investigate Asphaltene risks over the oil production pathway (at reservoir formation, and from wellbore to surface facilities) & Different Gas compositions to investigate the effect of rich Gas-Cap gas and injected lean gas on the Asphaltene stability. Also, the segregation of the nature of Asphaltenes within the reservoir has been investigated by using the experimental approach named ‘ASCI (Asphaltene Solubility Class Index) experiment’ introduced by the international partner (SPE-164184) to rank Asphaltenes’ solubility with atmospheric dead oil samples taken in different locations. In addition to that, 2 more experiments were performed: Organic – Inorganic test on solid sample to determine the composition and the nature of the solid deposit (whether it is Asphaltene or other type of depositions) & SARA analysis on atmospheric samples. This paper presents the improved work-flow based on the collaboration of the local operator and the international partner, introduces the use of ASCI (Asphaltene Solubility Class Index) experiment and discusses the results of the study and its way-forward.

The lower cretaceous Formation reservoirs in Offshore Abu Dhabi represent a regressive cycles of sedimentation developed with shoal, laggonal, subtidal and supratidal sediments. This formation includes various types of lithologies along the reservoir column: Anhydrite alternating with Dolomites, limestone.In such mature, heterogeneous oil reservoirs with a large gas cap, information may improve cost effective productivity, reduce the risks and improve the oil recovery. Special analysis of pressure measurement, fluid scanning and sampling while drilling is important to challenge open hole log saturation, to understand the behavior of each layer in the reservoir, to assess the communication between the sub layers, and to enhance the development schemes. This study is a synthesis of all the Open-hole Vertical Pressure Profiling data sush as formation evaluation and sampling that has been performed through the history of the fields.Investigations have been conducted on the identification of the in-situ reservoir fluid nature; the hydraulic vertical communication between layers; pressure maintenance mechanisms effect and pressure evolution through time and its link with lateral communication.Furthermore from operational point of view best practices have been developed for a safe and efficient procedure in terms of data acquisition and analysis with the limitations of the formation testing tool.

The Maximum Reservoir Contact (MRC) concept was developed to improve well productivity and sustainability by maximizing the contact area with target reservoirs. MRC is a proven technology for the development of tight/non-economical reservoirs. Completion design for MRC wells plays a vital role in enhancing well deliverability, monitoring and accessibility. MRC technology was put into application to appraise a tight and thin heterogeneous carbonate reservoir in a giant offshore field in Abu Dhabi. Different completion scenarios were simulated to select the best suited completion to achieve enhanced well deliverability, monitoring and accessibility. Heavy casing design with liner and tie-back system was finalized to maximize accessibility and achieve proper isolation behind casing. A special pre-perforated liner was also designed to eliminate the pressure drop across the wellbore. The MRC drain was divided mainly into two sections, blank pipe and pre-perforated liner equipped with swell packers for isolation. Pre-perforated liner was subdivided into compartments for proper flow distribution, accessibility and monitoring. The blank pipe was utilized to isolate the potential gas zone. Fractures and faults presented a major challenge in achieving the well objective. Special logging requirements were also considered for proper characterization of the suspected faults/fractures as well as to confirm and locate the source of gas risk for compartmentalization. For proper accessibility, monitoring, stimulation and sustainable production, tapered upper completion was designed and equipped with permanent downhole gauge for continuous monitoring. The well was successfully drilled and completed with production performance exceeding expectation which will indeed pave the way to apply MRC technology to unlock the all-out potential from undeveloped tight heterogeneous reservoirs within the field.