When analyzing well performance in carbonate reservoirs, the traditional approach usually requires the best practices from pre and post stimulation analysis. Most techniques require an understanding of production performance, which can be divided into two categories. The first is related to reservoir performance away from the wellbore i.e. permeability, fracture network, reservoir pressure, boundaries and secondly, the near wellbore and zonal contribution i.e. permeability-thickness, skin, oil and water influx from individual producing zones. In order to develop a full picture of how these two categories contribute to production performance, a detailed analysis should be conducted to understand their interaction. Low permeability carbonates and chalk fields often require long multi-stage frac'ed horizontal wells which further complicates the analysis due to lack of measured data in each stage. The Ekofisk filed development is a mature water flood, which includes both deviated and horizontal wells. Deviated wells are placed in the more crestal location, while the horizontal wells are generally placed towards the flanks where reservoir properties are of lower quality as compared to the field's crest. Production performance and optimization is largely dependent on efficient zonal stimulation, well and reservoir management. Understanding the distribution of fluid phases along the well, especially the water influx, may enable timely executed water shut-offs to mitigate water breakthrough. The traditional technique of understanding where and how much oil and water are being produced, require well intervention through production logging (PLTs). Well interventions are often difficult to execute due to limited access to platforms, the high cost of wells and production deferments. All of these factors limit efficient production optimization due to the inability to collect data in a timely manner for analysis. Furthermore, experiences from the Ekofisk field indicate that PLT data often gives inconclusive results due to known challenges of interpreting PLT data from horizontal wells. An intervention free and cost efficient approach using inflow tracers has been piloted to acquire early time data, in addition to acquiring well and reservoir understanding throughout the well life. This approach was successfully developed and tested in a newly drilled horizontal Ekofisk field producer. The well was equipped with inflow tracers permanently installed in the completion string to identify individual zone's production contribution including the split by oil, gas and water. In addition, unique intra well tracers were injected into each zone during stimulation to gain knowledge of the stimulation efficiency. During well start up, clean out, transient and post transient production periods extensive sampling programs were executed. As a result, sufficient data has been acquired in order to complete reservoir characterization analysis together with traditional Pressure Transient Analysis (PTA), and then followed by production optimization. The acquired tracer data and interpretation has been compared with conventional PLT interpretation to verify the former. This is the first integrated application using permanently installed inflow tracers, injected intra well tracers and pressure data interpretation solution for reservoir characterization and production optimization performed.

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When improving field production, the traditional focus on drilling activity means that the benefits from effective Well and Reservoir Management (WRM) are often overlooked. Within Sakhalin Energy's Astokh area, an integrated field management approach has realized significant oil gains with minimal well interventions.When phase 1 of the Astokh development was completed in 2001, only seasonal production via an FSO was available. Associated gas was re-injected into the crest of the reservoir, leading to a secondary gas cap. When this caused gas coning in updip wells, oil production declined because the gas handling equipment limits were exceeded. Pressure maintenance wells in 2004 helped to minimise associated gas levels, but it was not until the Sakhalin Energy Phase 2 project came on stream in 2009 that year round export was available, allowing gas injection to cease. With the drilling rig not available until Q4 2011, the application of effective well and reservoir management was the only way to address the declining field production.The primary focus was the depletion of the secondary gas cap. The first decision was to open high GOR updip wells whilst managing others through downhole shut-off / choking of zones. Secondly, water injection well volumes were optimized depending on levels of gas cap depletion in various areas of the reservoir. Thirdly, the reservoir model was regularly updated, reflecting gas cap behaviour seen through GOR levels in updip wells. Executing this approach required the gas compression facilities to operate at > 100% efficiency and put strain on the equipment, so a significant effort to maintain the reliability of the surface facilities was pursued.Within a year of implementing this multi disciplinary approach, three wells more than doubled their oil production rates.