An integrated and collaborative study was required in order to determine the most cost effective field development scenario while ensuring collision risk mitigation, to define and validate the well planning and slot allocation for the wells scheduled for the next ten years as part of the re-development due to a new sub-surface strategic scheme that was later extended to the full lifecycle of a green field offshore Abu Dhabi. The workflow included data, feedback and participation of four main stakeholders: Sub-surface Team, Petroleum Engineering Team, Drilling & Completion Team and Surface Facilities Engineering Team. The process started with the provision of the targets by the Petroleum Engineering Team, previously validated by the Sub-Surface Team to the Drilling & Completion Team. The second step included generation of preliminary trajectories including high-level anti-collision analysis against existing wells as well as other planned wells; this step also included validation of the Completion requirements based on the preliminary drilling schedule and equipment availability. The trajectories were then sent back to the Petroleum Engineering Team for well objectives validation and finally a multi-disciplinary session with the Surface Facilities Engineering Team, Petroleum Engineering Team and Drilling & Completion Team was executed to ensure readiness of surface installations based on the drilling schedule; as part of the outcome of this session multiple iterations occurred until alignment and agreement of all the stakeholders was achieved. The outcome of the workflow was the generation of full field development study including the preliminary trajectories, their respective slot allocation, high-level anti-collisions and estimated Drillex (Drilling Capex) validated and agreed by all stakeholders. This novel approach to the integrated multi-disciplinary collaborative field development well planning provides multiple benefits such as: 1. Fast delivery of scenarios for field development well planning, reducing the cycle time to less than half of the conventional time required. 2. Generation of multiple scenarios instead of a single scenario, allowing further optimization of cost and risk reduction without compromising expected production targets. 3. Early understanding of the completion equipment requirements to ensure availability based on the drilling schedule. 4. Quick response to unplanned changes based on the understanding of the full field scale planning allowing swapping of wells with minimum to impact on cost, risk and operations. 5. Full In-House process that represents a continuous and dynamic project allowing constant fine tuning based on new data and new models instead of a fixed time stamp, static, project with a single report outcome.

The ADNOC Offshore oilfield located in the Arabian Gulf is being developed utilising various wellhead towers, infield pipelines and a standalone super complex. The field development team devised an updated subsurface plan to achieve production targets beyond the original plan. The incremental oil necessitated assessment of original surface facilities design to identify any bottlenecks and unlock constraints. A set of production forecasts were initially provided as basis for assessment covering various scenarios and range of reservoir uncertainties. To manage these uncertainties, the facilities and subsurface development teams worked in an integrated and iterative way. The production profiles were used to assess and develop understanding of surface facilities such as oil flowline network, water injection supply and network, gas lift networks and the major equipment. The assessment results provided guidelines on the process facilities constraints which were feedback to subsurface team. An optimised subsurface development plan was then generated respecting the facility constraint and leveraging the existing facilities design to utilise ullages. An initial view of investment to produce incremental oil considered installing three new wellhead towers, a new manifold platform and a new water injection platform both linked to the super complex and a new main oil line installation to transfer partially stabilised oil from super complex to oil processing plant. The technical evaluations and the decision analysis resulted in a low-cost solution that was needed to ensure that the field's incremental oil production is economically viable. The integrated approach not only allowed selection of techno-commercial robust solution but also allowed optimisation of investment providing flexibility to accommodate the key project uncertainties. This was achieved by deferring the investment to future by descoping the overall development plan in two separate projects - achieve production plateau and sustain plateau. The interim period between the two projects would provide time to resolve the subsurface uncertainties and an opportunity to revisit future development strategy without committing any investment. In addition, the original UTC was significantly improved. This approach emphasised the importance of having a flexible surface facilities solution in accommodating the developments in the subsurface field development strategy especially in an offshore environment and during the early field production period. This paper presents an approach followed for optimisation of an offshore oilfield development plan under various surface facilities constraints.

ADNOC Offshore successfully revamped the field development plan of one of its reservoir in view of the newly acquired data during initial production phase from 5-Spot pattern drive to Semi-peripheral water injection strategy to ensure delay in water breakthrough and improved sweep efficiency. At the first stage, multi-disciplinary subsurface study was conducted utilizing and carefully analyzing all the available data. This lead to the development of the new model that was able to replicate the field current behavior. Study of the several development strategies helped to analyze field behavior with different development schemes. The change in the development strategy from 5-Spot to Semi-peripheral resulted in an increase of plateau length for four years with an increase in recovery of 6% at economic cut-off limit. Due to high productivity of the reservoir, wells were able to produce without any pressure support contrary to initially predicted performance that lead to the reduction in the water injectors and additional oil producers were incorporated in the development plan that would drain the reservoir more efficiently supported by gas lift. As part of further optimization, horizontal injectors were converted to slanted vertical injectors equipped with inflow control valves that provided full control and selectivity of the injected volume that would provide production assurance in such a high heterogeneous and differentially depleted reservoir. To support this change pilot test was performed that proved successful without jeopardizing the injectivity of the reservoir compared to horizontal well. Implementation of the devised project is in progress that marks the importance of the initial production behavior of the field that could lead to a different development strategy. This project is unique in a sense that with all the additional constraints of surface limitations particularly in the offshore environment, this project is on its path of successful completion.