Including "smartness" in your field does not necessarily add additional expenditures. ADNOC Offshore piloted a new well completion design combining Interval Control Valves (ICVs) in the shallow reservoir and Inflow Control Devices (ICDs) in the deeper reservoir, both deployed in a water injector well for the first time in the company. The objectives were to improve reservoir management, reduce well construction complexity and achieve one of the main business targets of cost optimization. This paper covers the subsurface study, detailed well construction design, completion deployment, well intervention and overall well performance in commingled injection mode. A multi-disciplinary study was conducted based on updated reservoir data available after the first two years of production in a heterogeneous multi reservoir field. This study showed the possibility of replacing the upper horizontal drain by a deviated perforated section. The authors identified the need of completion compartmentalization to overcome challenges such as high reservoir heterogeneity and uneven pressure depletion enforced by non selective acid stimulation. As part of the evaluation, a simulation was performed to evaluate the expected injection performance across the four zones with different combinations of ICVs and ICDs in order to cater for different injection scenarios. As a result of the integrated analysis, a new well completion design was deployed to optimize a Dual Horizontal Water Injector into a Single Smart Completion with 3 Inflow Control Valves (ICVs) covering the upper perforated zones and 14 Inflow Control Devices (ICDs) with sliding sleeves across lower lateral reservoir. Cost savings and reduction of rig time was achieved with this new completion design demonstrating very pro-active participation from all involved teams, ADNOC Offshore and Service Companies. The requirements to complete high and low permeability zones in one single well can be successfully accomplished. Firstly, mitigation of early water breakthrough is achieved by incorporating surface water injection control in high permeable zones and secondly, the injection target for the low permeable reservoir is also delivered. Building on the successful results and captured lesson learnt, this new well completion design provided the capabilities to optimize the water injection plan while reducing costs. Therefore, the project has passed the trial phase and the team proposed its implementation.

After a long history of unsuccessful appraisal wells, a new phase of reservoir appraisal focusing on data gathering for reservoir and fluid characterization led to positive results. Fluid sampling, acid recipe, formation pressure, and horizontal drilling were key factors for the successful appraisal. This reservoir is now a significant upside for the field development plan. During the early phase of field development, careful data gathering plan was designed to characterize the reservoir. The plan included coring, logging, reservoir formation pressure, downhole fluid analysis, fluid sampling, conventional Pressure, Volume, and Temperature (PVT) studies, and asphaltene and flow assurance studies. After collecting downhole oil samples, a compatibility study with acid recipe was performed and many chemical additives were tested to find the optimal one. A horizontal drain was drilled to maximize the reservoir contact. The well was tested with drill stem test (DST). Reservoir formation pressure acquired in 4 pilot holes at locations covering the reservoir confirmed fluid mobility, initial reservoir pressure, and possible oil pool limits. Downhole fluid analysis and sampling allowed the characterization of the reservoir fluid properties. Conventional PVT, asphaltene and flow assurance studies confirmed light oil with good flow potential. However, the compatibility study with existing acid recipe showed a high increase in fluid viscosity. This could prevent the well from flowing after matrix acidization. Naphta, among many tested chemical additives, proved to be the best to resolve the viscosity increase. The horizontal drain was successfully acidized with the new acid recipe and the well flowed oil during DST for the first time, 46 years after the field discovery. The well was tested through separator at different chokes before the main pressure build-up (PBU). The well was shut-in for 78 hours. BU analysis showed that reservoir permeability is in line with previously collected cores. Although earlier appraisals were successful in upper reservoirs, a classic approach to reservoir appraisal of this thin oil reservoir failed. Our approach of carefully planning the data gathering sequence, testing acid and oil compatibility, proved essential to understand the past failures, correct the shortcomings, and carry on a successful appraisal.

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.

The accurate metering of flow rates across the production chain, from sandface to sales point or custody transfer point is of vital importance. With the use of multiphase flowmeters (MPFMs), measurement of multiphase flow under dynamic conditions is possible. In well tests, the assurance of optimal flowmeter performance is of great importance because test results can significantly impact long-term field development planning and well management. We highlight the integrated approach implemented to improve flowmetering performance for a new oilfield offshore UAE In offshore fields, MPFMs have been installed on production towers to measure production of individual wells. In the first phase of field development, commingled flow from all wells is also metered at the outlet of the manifold tower (MFT) before entering the subsea line to the processing facility. The installed MPFMs eliminate the need for traditional test separators or dedicated test vessels. However, since multiphase flow is complex, turbulent, and chaotic, the acquisition of accurate, reliable, and repeatable rate measurements can be a challenge. Fiscal measurements must also meet statutory requirements for accuracy in hydrocarbon accounting and production allocation. We present the case study of a new field, the initial challenges encountered in achieving quality test data, and the systematic approach established to streamline flowmeter performance. This approach comprises representative fluids description, results validation, and calculation model optimization, which has resulted in improved performance of wellhead and MFT flowmeters. The process of streamlining flowmeter performance verification and optimizing flowmeter utilization to track individual well performance has resulted in cost savings and improved production optimization. Well-specific pressure-volume-temperature (PVT) models have provided optimal conversion of line conditions to standard conditions, with reduced uncertainties introduced by pressure, temperature, and effluent variations. As a consequence, ideal production allocation factors were achieved, yielding confidence in the use of well test data for production and reservoir management purposes. An added benefit is the increased confidence in the data quality for history matching of the dynamic model. Effective production monitoring as new production streams from different reservoirs come on line has enhanced production reconciliation due to reduced uncertainty from commingled flow and improved production forecasting. The principles employed in multiphase flow measurement technology are not new. However, real-time, accurate flow rate measurements are essential for good decision-making, sound engineering analysis, and effective life-of-well management. The application of a case-by-case approach to flowmeter configuration, combined with an efficient monitoring approach, has proved very valuable to achievement of effective reservoir monitoring and well management.