Long-Term Production Results of Polymer Treatments on Producing Wells in Western Kansas

Abstract

Summary This paper describes the analysis of the long-term oil production performance of 37 near-well polymer treatments on 26 producing wells in western Kansas to determine incremental oil recovery resulting from the treatments. Estimated incremental oil recovery from the 37 treatments was 76,500 STB of oil from 39,600 Ibm of polymer injected, or 1.93 STB/lbm of polymer injected. The polymer treatment types giving the best oil recovery performance were solutions of anionic polyacrylamide (ungelled) and cationic polyacrylamide gelled in situ with the chromium reduction/oxidation process. Both gave incremental oil recoveries of 2.6 STB oil/Ibm of polymer injected and had average treatment lifetimes exceeding 1 year. Introduction Polymer treatments of injection and production wells have been used extensively for fluid diversion and to increase oil recovery. Injection of high-molecular-weight polymers increases the viscosity of the injected water and reduces the permeability of the porous medium to water. In producing-well treatments, the injected aqueous polymer solution preferentially flows into zones that exhibit high permeability to water and subsequently restricts the flow of water when the well is put back on production. Polymer injection has two effects: the water production rate decreases substantially and the pressure drawdown into the wellbore often increases greatly, resulting in an increased oil production rate. During the 1970's, Phillips Petroleum Co. conducted 37 polymer treatments on 26 producing wells in western Kansas. All but one of the treatments were on wells completed in the Arbuckle dolomite formation. The formation has been characterized as a highly fractured, vuggy dolomite with varying amounts of chert and with reservoir characteristics varying from field to field throughout the Central Kansas Uplift. Permeability ranges from 50 to 5,000 md; porosity ranges from 1% to 20%, with an average of 15%. The oil zone is estimated to be 5 to 50 ft thick; the total Arbuckle zone is up to 300 ft. Oil viscosity ranges from 3 to 13 cp. The reservoir drive mechanism is primarily bottomwater drive, and the wells are completed at the top of the formation to delay the onset of water production. Water production comes primarily from coning. Because of the natural fracture network, vertical permeability is high and there are few vertical barriers to restrict water coning.