A significant challenge in the mature South Kuwait Burgan field is assuring maximum hydrocarbon flow through high water-prone sandstone intervals. Recently, water control or conformance treatments have been considered to make oil production from these reservoirs more economically feasible. This paper discusses the application of a novel downhole chemical methodology that has created a positive impact in overall productivity from this field. The production profile in this field has been challenging in terms of increasing water volume, which poses a great threat to continued economic viability and may lead to lower production rates, a reduction in recoverable reserves, and premature abandonment. Some of the production-gathering centers cannot handle the ever-increasing volumes of produced water and are operating beyond design capacity. In order to solve this challenge, a downhole chemical treatment was modified as a fit-for-purpose treatment to address the unique challenges of electric submersible pump (ESP)-driven well operations, formation technical difficulties, high-stake economics, and high water potential from these formations. A unique hydrophobically modified water-soluble polymer (HRPM) was implemented in a high water-cut well to selectively reduce water production. Because this well was producing with an ESP, the treatment was pumped down the annular space. A preflush was pumped ahead of the HRPM treatment to remove deposits that could prevent the polymer from effectively adsorbing to the rock surface. The treatment was then overdisplaced with brine. This technology incorporates an HRPM that is adsorbed on the rock surface, resulting in the alteration of rock surface characteristics. The hydrophobic modification to the base polymer chain adds unique associative properties to the system, which selectively reduce the water's effective permeability in the reservoir, impeding water flow and facilitating increased hydrocarbon flow. A direct result of the implemented treatment is that the post-operation well test and production data show a high sustained hydrocarbon production at a smaller choke size with significantly reduced water cut. This successful treatment confirmed the optimized conformance technology as a solution for the first well in this field. In order to achieve maximum reduction in water production, this technology is customized based on the temperature and permeability of the treatment zones, thus ensuring it is fit-for-purpose. Furthermore, this paper summarizes the candidate selection, design processes, challenges encountered, production response, and lessons learned from this treatment and can be considered a best practice for addressing high water production challenges in similar conditions in other fields.

The mature Great Burgan field comprises of more than 2000 wells to date, many of these wells utilize artificial lift in their production to maintain production targets. Tubing leaks and integrity issues pose major challenge to the artificial lift pump; these leaks eventually cause pumps temperatures to exceed the operating limit, trip and stop production. The waiting time for a workover rig is about 4 months, this converts to a significant loss of oil production in every well with tubing integrity issue. To reach and sustain the production target, rigless tubing repair is perceived as a viable quick solution to maintain production until workover rig becomes available.

It has always been a challenge to accurately detect downhole sand producing zones. Older generation acoustic based sand detecting technologies were subject to error due to background noise related to the fluid production. Due to the common false detections with the legacy measurements, remedial workover plans were compromised (Adil, 2020) A new technology that can differentiate between sand production and background fluid related noise has been developed. This technology can quantify the sand grain count through a piezo-electric sensor. In this paper, a unique comprehensive study was conducted across a sector of the Greater Burgan field to better understand the variables contributing to sand production through integrating the static model along with the dynamic production profile which included the new, state-of-art downhole sand detection technology. Based on the results, a guideline was formulated to predict the future sand producing wells. This helps to proactively anticipate and therefore, better manage the sand production challenges. This paper covers the results of nine wells logged across the same reservoir units. The main objective was to identify and quantify the sand producing intervals. The secondary objective was to determine the water producing zones. Wireline production log were combined with this new technology in all the wells to obtain the fluid production intervals along with the sand producing zones at the same conditions in the same run. Along with the spinner, water hold up probes pinpointed the water entries. The sand impact detection tool provided the fourth phase, sand, with excellent repeatability. Multiple rates were conducted in some of the wells to determine the critical drawdown pressure at which sand production occurs.

The case study describes a modeling and simulation study of an inverted ESP completion to address three fundamental objectives. A) Increasing the ultimate oil recovery in the massive sands of Cretaceous age in Greater Burgan field by managing water production B) Mitigating the rapid water coning conditions in this high permeable water drive reservoir and C) Designing an optimal operating strategy with Downhole Water Sink (DWS) to control water production and manage well performance. A 2×2km sector was carved out from the full field geological model with 12 wells including the study well. The study well was producing at high water cut at the time of the study. All static properties were updated, and the model was history matched for production, pressure and saturation. Several sensitivity runs were performed, and prediction scenarios were run for 5 years to observe well production behavior in time. The well model was setup with an inverted ESP between straddle packers to produce water from below OWC and inject into bottom reservoir with a production string above to produce from the oil zone. This setting ensured a reverse oil cone being generated from below OWC in the reservoir under production. The aquifer model was finite in size enabling bottom water influx. Simulation results showed that implementation of DWS technology made the water production reduced by 18% during five years with an increase in oil production of nearly 25% in the study well. To maintain continuous well offtake rate, a range of water rates to be produced and injected to bottom reservoir have been studied. Several iterative runs were made to investigate the best completion interval and injection & production rates. The profiles of oil water interface near well bore indicated good reduction in the cone height as compared to normal completion. The results also showed significant improvement in oil recovery within the drainage radius of the well from the simulations. Simulation results provided good understanding of the saturation change near well bore area under different production rates. Prediction runs were made for sustainable oil production under natural flowing condition and the conditions to switch over to production under artificial lift. Production of thin layers of remaining oil from within high permeable massive Burgan middle sands has been a high concern due to very high water cuts because of coning. The study results have provided encouraging option with DWS technique to improve recovery from the reservoir.

This paper describes a dynamic modelling and optimization study to investigate the viability of deploying intelligent completions for well management in a mature oilfield in order to mitigate the challenges of increasing water cut and rapid diminishing of surface locations for new wells across the Greater Burgan field. Reservoir simulation is used to assess the potential benefits of installing Flow Control Valves (FCVs) in a candidate well, to control production from multiple reservoir zones. A representative sector model is defined around the candidate well, to include surrounding wells that could influence its flow behaviour. Reservoir properties are extracted from a fine-scale geological realization and updated using current well logs. Sensitivity studies are performed to determine the appropriate size and grid design for simulation. The well is planned to be completed across six producing reservoir zones with a single tubing and an Electrical Submersible Pump (ESP). In the optimization strategy, the FCV aperture openings are adjusted over the lifetime of the well, to maximize the Net Present Value, while meeting operational and strategic constraints. The robustness of the forecast outcomes are highly dependent on the quality of reservoir characterization. A sector model large enough to represent the effects of reservoir heterogeneities and interference from other wells, was used. The efficient optimization workflows used here can be generalized for similar analyses of other wells and other fields. The optimized results demonstrate that installation of FCVs can help to meet the simultaneous objectives of boosting oil production while reducing water production. This is achieved by choking back the deeper high-water production zones to accelerate oil production from the upper high oil saturation zones, while also targeting offtake to induce the shallower low-pressure zone to deliver more. The large initial capital outlay, comprising the equipment and service cost of the FCV installation is fully offset within the first year of production, post installation. This study highlights the significant upside benefits for the management of complex brown fields such as the Greater Burgan by adopting smart well completion strategy. Improving well production performance, and supporting multi-zone completions, should also enable reduction of well counts for fields with existing high well density and lack of surface space to accommodate many new dispersed wells.