This paper sheds light on the design and field results of a strategic Long-Term Polymer Injectivity Test (LTPIT) to de-risk phased commercial polymer-flooding in the largest sandstone field worldwide in pursuit of production acceleration, reserves growth and cost optimization. Effluent water with up to 170,000ppm TDS was used in conjunction with a pre-selected sulfonated polymer to evaluate injectivity at multiple rates and polymer concentrations under sub-fracturing conditions. Reservoir parting pressure was judiciously estimated to be around 2,500 psi. Polymer and water injected below parting pressure flowed into and through the Wara reservoir matrix as evidenced by the increase in downhole pressure with increasing injection rate in line with Darcy’s law. Polymer solutions expressed in-situ viscosities of up to 2.75 cP when injected below fracture parting pressure while displaying pseudoplastic flow characteristics. Water on the other hand displayed Newtonian behavior. Polymer adsorption onto the Wara formation developed a residual resistance factor of 1.17 for an effective water permeability reduction of approximately 20%. Polymer injection evidently improved reservoir conformance and resulted in more uniform zonal intake. Injected fluid distribution between 4,693 to 4,706 ft decreased from 85% to 71% and injection out of this depth range increased from 3% to 15.5%. Step rate testing with varying polymer concentrations evinced that increasing polymer concentration will decrease injection rate and, therefore, the duration of any mobility control polymer flood in the Wara reservoir will be affected by polymer concentration. A dynamic model was developed using CMG STARS and calibrated to wellbore petrophysics, polymer concentrations, downhole pressures, injection rates and pertinent surveillance/monitoring data. Numerical simulation sensitivity analysis indicates that 1800 ppm of the pre-selected sulfonated polymer (ZLPAM 40520), dissolved in effluent water, is the optimal concentration with 0.8 PV of injection being the optimal injected volume in terms of oil recovery and project economics. The benefits associated with polymer injection in terms of production acceleration, incremental recovery and cost optimization can be significantly increased by fast-tracking polymer injection using optimal well configuration. Performance forecasts using field data demonstrated that polymer injection has the potential to considerably reduce water-handling requirements, thus resulting in major cost savings. Furthermore, assuming an oil price of $80/bbl, drilling additional wells to establish 40-acre spacing for polymer injection can result in 9.4% incremental recovery at a Unit Technical Cost (UTC) of 19.3 $/bbl inclusive of the cost associated with polymer, additional wells, surface facilities, operations and maintenance. The results of this strategic field trial establish the techno-economic feasibility of phased commercial polymer-flooding in the Wara reservoir of the Greater Burgan field in Kuwait.

The Greater Burgan field in South-East Kuwait is the world's largest sandstone oilfield and the second-largest conventional oilfield. The Wara reservoir, in the Greater Burgan field, is a prolific sandstone oil-producing formation. Peripheral water injection into the Wara reservoir is in progress for pressure maintenance and to improve oil recovery from the flank areas. Polymer injection has also been identified as a practical EOR method that can potentially increase oil production and recovery from the Wara reservoir. In view of that and, as a follow-up to a previous Long-Term Polymer Injectivity Test (LTPIT) (Murayri et al. 2022), a second LTPIT was carried out targeting a different area within the Wara reservoir. This paper describes elements of the polymer injection predictions approach, results obtained from a dynamic simulation sector model, before and after polymer injection, in pursuit of phased commercial polymer-flooding development using fit-for-purpose modularized water treatment and polymer mixing/injection facilities. Prior to the commencement of polymer injection, a representative 3x3 km sector was extracted from the full-field dynamic model. A fine grid numerical simulation model was then history matched and calibrated using production/injection history and Step Rate Test (SRT), Pressure Fall-Off (PFO), and Injection Logging Tool (ILT) and High Precision Temperature-Spectral Noise Logging (HPT-SNL) surveillance data. This model was set for predicting polymer injection rates to ensure injection under matrix conditions, at different polymer concentrations, to guide field implementation over a period of 3 months. Pre-LTPIT modeling results demonstrated that injection at commercial rates of >2,000 bpd is possible with polymer concentrations ranging from 1,500 to 1,800 ppm in accordance with the targeted in-situ polymer solution viscosity. During LTPIT field implementation, downhole pressure and temperature were monitored real-time in addition to wellhead pressure, injected polymer solution viscosity and injection rates to evaluate performance and update the sector model. Thereafter, reservoir simulation sensitivity runs were extensively investigated to design an optimal phased commercial development plan. This plan was developed by optimizing well requirements, injected polymer Pore Volume (PV) and concentration. A polymer PV of 0.8 and a concentration of 1,800 ppm were recommended accordingly in conjunction with 40 acre inverted 5-spot patterns. Economic evaluation was performed while considering water-flooding performance as a baseline. The incremental benefits associated with oil production gains and reduced water handling requirements were evaluated against the envisioned investment in additional wells and polymer injection. The optimal case showed an incremental oil recovery factor of 7% over a period of 10 years. This paper presents a case study wherein fit-for-purpose reservoir modelling is integrated with LTPIT surveillance/monitoring data to maximize the techno-economic benefits of phased commercial polymer-flooding in the Wara reservoir of the Greater Burgan field.