Integrating High Resolution Sector Scale Dynamic Modeling into a Successful Long Term Pilot Polymer Injectivity Test for the Wara Reservoir of the Greater Burgan Field of Kuwait
Authors: Al-Murayri Mohammed Taha , Al-Qattan Abrar , Wafaa Al-Ghanim , Kakade Shweta , Banerjee Anirban , Mascagnini Carlos , Khamatdinov Rafael , Ali Chughtai Muhammed , Andrianov Alexey , Malcolm Pitts 
Published: March 2023

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 &gt;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.