The multidisciplinary authors have summarized the results from the Autonomous Inflow Control Device (AICD) deployment in multiple oil fields, and presented it in this paper as a practice worth replication in a similar heavy oil environment, due its many benefits in optimizing field development. AICDs have been tested mainly in labs and controlled environments with few comprehensive field trials. This paper will form the basis for that which will add to the state of knowledge in the industry. The AICD technology was piloted in few wells of these fields. It comprises of mechanical devices installed with the sand face completion, which react in real time to the properties of the flowing fluids, decreasing/delaying the water influx (or gas if it would be the case) from high productivity zones, promoting increased oil production from other compartments of the formation, therefore, equalizing the drawdown along the horizontal section of the well and performing a dynamic water shut-off operation. No cables are required, as the devices work on the basis of viscosity and density difference between the oil and the water. The AICD-completed wells showed initial water cut in the range 1% to 2%. Which has reduced significantly in comparison to nearby analogues. The initial net oil rate resulted to be more than 2 times of the expected one, with an acceleration of ~10,000 bbls of net oil during the first month. After the initial production period, the technology is still delaying the aggressive water cut development usually observed in these fields, having provided 2 times the expected net oil rate during the first 3 months, with an acceleration of approximately 20,000 bbls of net oil over this period. It has been concluded that the application of the technology is successful and will be deployed as a baseline in all future horizontal wells drilled.

Waterflood response in a brownfield with complex reservoir dynamics have significantly delayed the expected water injection response in Field ‘A’. The field is one of the highest oil producers in Oman South, spead over ~37 Km2, with more than 400 active wells, contributing > 90,000 BoE/d over the last 3 decades. The field is producing under strong bottom aquifer water drive and improved oil recovery waterflood. Current field development is focused in drilling horizontal in-fill wells and maximize recovery through well reservoir and facility management (WRFM). Production is from a combination of Mahwis aeolian and Al Khlata glacial reservoir formations. Sub-surface challenges are to arrest pressure decline, enhance sweep efficiency, ramp-up water injection (target > 440,000 BoE/d), and source additional water and manage complex operations. The produced water from oil producing wells post treatment gets re-injected into the aquifer ~100m below oil water contact (‘Deep Injection’) with 38 vertical injectors. This ‘Deep Injection’ albeit have prolonged water breakthrough has yet not delivered the optimum oil drive efficiency. One of the key subsurface challenge is the unfavorable mobility contrast between the oil and water causing early water breakthrough. Field wide variable mobility contrast, presence of intra reservoir baffles and enlarged size of the aquifer compared the legacy model assumptions triggered a transformation of the improved recovery strategy of the field – both short term and longer term. More effective injection strategy through ‘Field Trials’ have now been deployed (viz. ‘Water Re-Distribution’, ‘Make-up Water Diversion’ and ‘Shallow Injection’) over the last two years. Initial response from these trials shows encouraging results in terms of pressure support and sweep efficiency. Learning from the trails are incorporated in the future development and asset management strategy. This paper highlights the ‘Field Trials’ – practical approaches implemented to manage and optimize the field performamance. In a cost competitive low oil price time the team focused in enhancing efficient and impactful trials which yields short-term production gains keeping in mind the longer term persepective.

The objective of this study is to evaluate and de-risk the extension of the Kahmah Group, which is a newly identified carbonate extension in the Eastern part of XX field, and to assess and unlock further appraisal and development opportunities. Eastern field correlation was done by correlating the wells that has encountered Kahmah carbonate, the ones showing low Gamma Ray (GR) traces. Well correlation was done mainly on Petrophysical properties of three vertical penetrations that show distinct and abrupt change from high GR (Base Nahr Umr Shale and/or Mahwis sandstones) to low GR reflecting Kahmah carbonates. Based on the thicknesses of Kahmah based on the vertical well data and commercial oil seen in all wells in the vicinity, thickness and expected oil distribution maps were created. The main findings from the correlation are: 1) Kahmah reservoir is divided into two pays and two non-pays zones as seen in XX-1H1. 2) The reservoir is thickest around XX-1 and thins out toward YY-10 to the south and disappears completely in XX-5 to the north, portraying a wedge- shape. Kahmah reservoir varies in thickness, with thickest interval encountered in XX-1 with 11m. The reservoir thins out towards the edge closer to YY-10 confirming the wedge-like structure. A conceptual understanding has been incorporated in generating cross-sections portraying and proving the wedge-shape structure of Kahmah. Like any other new formation development, many uncertainties are associated with Kahmah development like formation extension, reservoir/fluid properties, pressure behaviour and others. The key observations from this project can be summarized as following: Different packages of reservoir. May be of different or similar propertiesExtension of Kahmah towards northern part of XX field is still highly uncertainContinuity of Kahmah Reservoir is uncertainReservoir pressure and communication with Mahwis formation need to be evaluatedReservoir and fluid properties also need to be evaluated