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Conventionally discovery to development of a heavy oil reservoir takes very long (Minimum 10-15years). However, significant volatility in the oil prices have required more collaborative workflows and strategies from operators and service companies to optimize cost and maximize efficiency and innovation. We present here a joint service integrated model between an NOC and a service company which was used in the fast track development of an unconventional heavy oil reservoir and resulted in discovery to production in record time. A conceptual field development plan was put in place for fast track development of the Lower Fars reservoir in the Umm Niqqa field after drilling and testing 26 exploration wells. The plan consisted of drilling and completing over 80 wells in conjunction with the construction and commissioning of an early production facility (EPF) to handle the sour heavy crude. Given the brief time and the unconventional nature of the reservoir, significant challenges were faced during the execution phase. To address the challenges, an integrated workflow was put in place combining multiple disciplines. The entire project required seamless integration between drilling, characterization, production and surface facility teams for flawless execution. The collaboration resulted in successfully drilling and completing all planned wells in less than 1 year. This paper describes the tasks performed during the project for successful execution. It was initiated by a robust assessment of the discovery in terms of OIIP and type of hydrocarbon. It further describes the construction of a fit for purpose field development plan. During the execution phase we explain the challenges faced while drilling deviated wells in soft unconsolidated reservoirs with extremely shallow kick off points. The challenges in logging and evaluating deviated wells to optimize completion strategy are also described. The optimization of testing, completions and artificial lift workflows played a significant role is assessing the dynamic behavior of these reservoirs. The workflows in conjunction with continuous production monitoring and workover planning allowed the minimization of non-productive time (NPT). We further highlight the surface facility designed for such heavy sour crude and the recommendation for future development.

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As a field development strategy, KOC is developing highly depleted reservoir. The field has been experiencing wellbore instability issues. Some recent wells have encountered stuck pipe and mud losses in clastic and carbonate sections. To reduce geomechanical related Non-Productive Time and rig days, it is important that combined effect of in-situ stress state and well trajectory on wellbore stability should be thoroughly investigated. Rock mechanical behaviours also need to be evaluated to optimize drilling practice. The growing appreciation of the effects of regional tectonics is making it crucial to move away from simplified characterisation of rock behaviour and to turn into advanced geomechanical modelling techniques to engineer better wells and fields. The advanced 3D coupled Geomechanical-Fluid-Flow modelling method combines input data of different origin, such as seismic data, petrophysical data, fluid-flow data and well logs. With such an integrated model, spatial variations of the in-situ stresses in the field are obtained due to reservoir structure, presence of discontinuities as we as because of reservoir depletion. The whole production history spanning seventy years was simulated. The 3D coupled geomechanical model was able to reproduce the observed wellbore instability events for fifteen wells drilled at different times and various reservoir depletion stages. Drilling instability events included tight spots, cavings and stuck pipe in major clastic sections; and mud losses in carbonate sections. Two blind tests for wells not used for model calibration were carried out to examine the mechanical properties, stress profiles and caliper logs within various formations. The match between the model prediction and the data was in good agreement. In addition, a 3D description of the mud weight was computed, which allowed to obtain drilling maps across the field highlighting zones of high, medium and low drilling risks. Such drilling maps enabled optimizing placement of future planned wells and provide guidance in mud weight design. Nevertheless, drilling through faults requires careful attention due to the localized stresses concentration developing along their geometries. High resolution near wellbore stability analysis helped to optimize the drilling mud weight for wells crossing faults. The powerful combination of multidisciplinary domains into one integrated 3D geomechanical model improved the understanding of subsurface behaviour. With such an integrated model, complex technical challenges as drilling complexities in the study field can be achieved and hence decreases the Non-Production Time by avoiding problems prior to their occurrence. The calibrated model showed satisfactory predictability for the whole production period and thus is used as a mitigate problem measure to placement of new planned wells.