First Successful Long-Term Polymer Injectivity Test in the Upper Burgan Formation of the Sabriyah Field to Fast-Track Phased Commercial Polymer-Flooding Development

Abstract

Abstract The Sabriyah field located in northern Kuwait primarily produces from the Mauddud and Burgan formations. The upper section of the Burgan formation is referred to as the Sabriyah Upper Burgan (SAUB) reservoir. SAUB reservoir consists of Cretaceous Albian age sandstones and spreads over an area of ~105 km2. This paper sheds light on the successful application of a long-term polymer injectivity (LTPI) test in the SAUB reservoir as a strategic milestone towards phased commercial polymer-flooding development. The main objective of the SAUB LTPI test was to evaluate injectivity at multiple injection rates and polymer concentrations under sub-fracturing conditions. Current EOR efforts target reservoir areas with unfavorable mobility ratio to improve oil recovery and unlock additional oil reserves. The location of the SAUB LTPI test was carefully selected to avoid faults and low channel thickness. Effluent water with TDS ranging from 150,000 to 200,000 ppm was used for polymer solution preparation. Iron content was relatively high (up to 200 ppm) but this was duly mitigated by maintaining low dissolved oxygen levels (i.e. <10 ppb). Fit-for-purpose modular skids were used for water treatment and polymer mixing/injection. A pre-selected sulphonated polymer was used based on extensive lab evaluation to overcome the high TDS, hardness, and temperature of the SAUB reservoir. A step rate test was conducted, and subsurface parting pressure was estimated to be around 5020 psi. Field data indicates that the selected polymer can be injected at commercial rates, under matrix conditions, using treated effluent water without plugging the reservoir. Important polymer rheological properties were generated using field data. Field and lab polymer data were found to be consistent. The LTPI test location average permeability that is lower than that of core plugs used during core-flooding experiments. Consequently, residual resistance factor was increased from a lab derived value of 1.3 to 1.5 based field data. Establishing favorable polymer injectivity under matrix conditions with relatively lower permeability is encouraging because better polymer injectivity is expected in areas having higher permeability. Pre and post polymer injection reservoir modeling were carried out on a sector reservoir model built in CMG STARS utilizing available lab data. Post calibration of the dynamic model was performed using pilot operational and laboratory data, predictive forecasts were then generated to evaluate the techno-commercial feasibility of polymer injection into the SAUB reservoir. Reservoir simulation results based on actual field data demonstrated that polymer-flooding accelerates oil production rates compared to water-flooding. Injecting 0.7 to 0.8 PVI (pore volume injected) at a polymer concentration of 1600 ppm was found to be optimal for commercial polymer-flooding development. The adopted approach and associated results demonstrate the viability of performing customized field trials to fast-track phased commercial polymer-flooding. LTPI test results validated earlier SAUB polymer-flooding forecasts for SAUB polymer-flooding development (SPE paper reference). An incremental oil recovery of 9.6 % can be achieved from polymer-flooding. Polymer-flooding ultimate total cost (UTC) over a period of 10 years was estimated to be 15.80 US$/bbl including the cost of additional wells.