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.

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

Water short circuiting leading to early, sudden and massive water breakthroughs in producer wells has been a lingering concern to oil operators for many years. Unfavorable mobility ratio leading to viscous fingering, horizontal wells exhibiting ‘the heel-toe effect’ and fields with fracture-fault activities are more prone to these kinds of unwanted water breakthroughs, suffering from oil production losses and higher operational cost for management of the excessive produced water. A brown field in the south of the Sultanate of Oman was experiencing massive water short circuiting within two of its patterns. [MJO1]While conformance was well established and dynamically confirmed through production performance and artificial lift parameters in most patterns within the field, the complicated inverted nine spot injector-producer pattern scenario[MJO2] was making it difficult to ascertain the offending injectors or unexpected flow paths leading to the condition within the study area. The lower API oil and slightly fractured and faulted geology was exhibiting conditions for injection imbalance and the challenge was to bring the high water-cut wells back to full potential and increase oil output whilst reducing water flow. To investigate the breakthrough occurrences and mitigate the challenge, chemical water tracers were introduced in the reservoir as a part of Integrated Reservoir Management framework to identify flow directions and offending injectors. The Phase-1 of the two-phase study, discussed in this paper, was carried out to determine reservoir conformance that was contributing to short circuiting and once the cause was identified and treated, Phase-2 was carried out post well intervention to validate the success of the treatment. Phase-1 of the tracer study was initiated in October 2019 where two injectors and nineteen producers across two adjacent patterns were traced with two unique chemical water tracers. Massive tracer responses were obtained within the first few days in few wells, directly pointing out towards the offending injector(s). Sampling and analysis for Phase-1 was continued for about six months, after which, a zonal isolation was carried out in one the identified injectors in August 2020. Cement was pumped across all the perforation intervals and a new perforation was performed across the top and bottom of the reservoir avoiding the middle intervals that were taking about 70% of injection as per production logging. Phase-2 of the study was initiated in March 2021 and continued sampling and analyses are still being carried out. With about 15% reduction in water cut and a three-fold increase in oil rate at the target producer, the study validated that an integrated knowledge of reservoir geology and production behavior coupled with tracer studies was a very successful strategy for managing short circuiting in waterflood reservoirs. The study showed that this sequence and combination of methods can be useful in effective treatment for wells experiencing high water cut across the world.