The appropriate economic balance between oil production rate, ultimate oil recovery and development cost can be difficult to find for complex naturally fractured reservoirs. This makes development drilling decisions and reservoir management of these reservoirs a very demanding task. Successful life cycle development of a naturally fractured reservoir can only be achieved by fully understanding the role of fractures on fluid flow at different scales, both inside the reservoir and near wellbores. Systematic fracture characterization becomes an essential prerequisite to gain the critical understanding crucial for successful development and economic success. This publication presents a complex low matrix permeability naturally fractured reservoir case study from a mature giant Middle Eastern oil field. Examples are provided illustrating the impact of fractures of different scales on reservoir fluid flow and well productivity, ranging from large scale fractures, previously often termed fracture corridors or fracture lineaments, to small scale micro fractures. Systematic efforts have been exerted over the past years to collect fracture characterization data, e.g. pressure transient, image logs and advanced formation tester data, including mini-DST (Drill Stem Test) formation tests. This data set has been complemented by other dynamic data like rate tests, pressure surveys and time lapse production logs, plus seismic and electromagnetic surveys. Based on the presented observations, it is evident that small scale micro features and associated connected fracture networks also play a role. If near wellbore large scale fracture features are not dominant, the small scale fracture networks determine the well drainage areas and become a controlling factor for reservoir well productivity and the overall reservoir recovery mechanism. As presented in this paper, the reservoir development strategy, including development well type, has been modified as a direct result on the improved understanding of the reservoir fracture system.

Horizontal wells are increasingly being completed with inflow control devices (ICDs) in order to equalize the flow profiles, avoid water coning, enhance oil production, and minimize or eliminate downhole crossflow. Evaluating ICD completions is important to assess well performance, water entry intervals, completion efficiency, and potential remedial actions. Advanced multiphase production logging tools can be employed to evaluate the effectiveness of ICD completions. This paper examines case studies of two horizontal wells drilled along well trajectories with large heel-to-toe pressure differentials. These wells were drilled in a large carbonate reservoir with moderate fracturing in areas of high structural curvature, which added to the heterogeneity. Crossflow can occur under static and flowing conditions with sufficient contrast in reservoir pressure along the wellbore. Crossflow is undesirable especially when water enters the wellbore in one region and flows into the formation at another region, thereby reducing oil relative permeability in the latter region. This can adversely affect well performance and ultimate recovery. Advanced multiphase production logs and wellbore simulation are useful in the determining minimum well production rate required to avoid downhole crossflow. Multiphase production logging profiles were obtained for the two ICD-equipped horizontal wells in this study. These logs demonstrate the efficiency of ICD completions in minimizing crossflow when wells are produced above critical flow rates. However, the problem of crossflow remains when such wells are shut-in or produced at rates below their respective critical rates. These results show that comprehensive evaluation of wells exhibiting crossflow is necessary to minimize or mitigate crossflow and optimize well performance. Additional ICD design enhancements are recommended to control crossflow below the critical flow rate and to minimize undesirable gas/water production. Introduction Horizontal wells are commonly used in the oil industry to accelerate production and lower unit development cost. Horizontal well performance is affected by many factors, including reservoir heterogeneity, well placement and completion design. In heterogeneous reservoirs, the displacing fluid (water or gas) tends to move faster in zones with higher permeabilities, which will cause early breakthrough of unwanted fluids with eventual bypass of some undisplaced oil (Ouyang 2009). This can affect the pressure distribution and hence can cause crossflow between layers.

Field development of a mature, highly fractured carbonate field presents several challenges. Most of the horizontal wells drilled in such fractured reservoirs suffer from early gas or water breakthrough because conductive fractures dominate the influx from the reservoir and cause an unbalanced flux profile along the wellbore. Premature gas or water breakthrough can result in poor sweep efficiency and reduced oil recovery for the well. To address the aformentioned challenges, passive inflow control devices (ICDs) can be used to equalize influx from the reservoir to the wellbore, thereby delaying gas or water breakthrough. However, during the life of the well, as water or gas breakthrough occurs, a passive ICD can be less effective in preventing water or gas production. This can effect well productivity and reduce the production life of the well, especially for a naturally flowing well. This paper describes how adjustable ICD technology with a sliding sleeve can be used as an effective reservoir management tool in mitigating challenges faced in a naturally fractured Middle Eastern carbonate field. Various examples from the subject field are presented to describe production challenges faced by barefoot and passive ICD-completed horizontal wells. The field cases suggest the need for adjustable ICD with sliding sleeve technology which provides a zonal shut-off option in case of water or gas breakthrough. A detailed workflow for usage of adjustable ICDs is described, and which includes well candidate selection, well monitoring and pre and post shifting well performance evaluation to determine which ICD unit must be shifted to a closed or open position. A dynamic simulation using a single-well model was also conducted to establish the benefits of a sliding sleeve on well production performance. An adjustable ICD with a sliding sleeve was chosen as the preferred completion technology over the passive ICD for horizontal wells for the subject field with a naturally fractured carbonate reservoir. A sliding sleeve integrated in an ICD is a simple and cost-effective tool for zonal water or gas shut off compared to conventional intervention technology available for horizontal wells. Sliding sleeves maximize the value of ICD technology by adding an adjustability feature to ICD to overcome the challenges faced by unexpected changes in well behavior and premature water or gas breakthrough. Dynamic simulation results also confirm the sliding sleeves can prolong the life of the well by reducing high water and free gas production, thereby increasing cumulative oil production.

Smart/Intelligent well completions are broadly used to maximize multilateral well productivity, restrict unwanted water and gas production, and improve sweep efficiency. To achieve the optimum economic values of smart completions, the surface and subsurface chock valves settings need to be frequently optimized using the best-in-class techniques. Applying the right optimization technique will ensure a successful and efficient optimization. The paper discusses an innovative production optimization approach using real-time modeling based on nodal analysis for multilateral wells. These multilateral wells are equipped with surface and subsurface downhole valves with various choke settings and downhole permanent pressure gauges. The technique utilizes the data collected during a conventional optimization and a commercial steady-state model. It estimates the flowing parameters of individual laterals, determines the optimum pressure drop across each downhole valve, and estimates productivity of each lateral during the commingled production at various choke valves settings. The approach was successfully field-tested and validated. The generated models were used to predict well performance at various conditions. The approach starts by collecting well rates and flowing bottom-hole pressure data at various chokes settings including commingled and individual lateral testing. The acquired data are used to calibrate the model, generate different production scenarios and optimize the performance of each lateral. Adoption of the technique among others facilitate better management of the multilateral wells production to fulfil both short and long term objectives, namely, optimizing production of these wells and improving recovery. In addition to the reduction of OPEX associated with the conventional procedures to test and optimize these wells.

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