Laboratory Evaluation Of Crosslinked Polymer And Alkaline-Polymer-Surfactant Flood

This paper discusses the feasibility of using cross-linked polymer technology and alkaline-polymer-surfactant technology to improve oil recovery in the Grand Forks Lower Mannville "D" pool. The Grand Forks "D" pool is a good quality channel sand withan original oil-in-place of 15.9 × 106 m3 (100 × 106 STB). The rock has a porosity of 25% and the permeability ranges from 1000 md to 10000 md with an average of 3000 md. The reservoir crude has a viscosity of 11 MPa •S at the reservoir temperature of 31 °C (88 °F) and a stock tank gravity of 898.4 kg/m3. Primary and Water-flood oil production has produced 25.5% of the original oil-in-place as of January 1986. Previous model studies and historical pool performance indicated that up to 60% of original oil-in-place could be left in the reservoir after water-flooding due to gravity effects and high vertical permeability. A scheme of combining cross-linked polymer technology and alkaline-polymer-surfactant technology has been developed to optimize the ultimate oil recovery. The application of cross/inking technology was investigated using cationic and anionic polymers with various cross-linking agents through linear coreflood and viscosity monitoring studies. The application of alkaline-polymer-surfactant technology was studied through interfacial tension, fluid compatibility, phase behavior, chemical adsorption, rock dissolution, and coreflood studies. Core flood studies included injectivity as well as oil recovery studies. The results of the laboratory studies indicate that the alkaline-polymer system can recover incremental oil over water-flooding of approximately 30% of original oil-in-place. With an addition of 0.1 % by weight of surfactant, up to 47% of original oil-in-place can be recovered. No injectivity and fluid incompatibility problems were detected. The test results also indicate that the residual resistance factor can be increased significantly by cross-linking. This should help improve the vertical sweep efficiency by diverting the subsequent injection fluids into the unswept zones. It was concluded that a chemical flood is technically feasible for the subject pool. Introduction The Grand Forks Lower Mannville "D" pool is located in southeastern Alberta (Fig. 1). Figure 2 shows the well configuration of the pool. The pool, which is a Lower Cretaceous channel sand, is one of the most productive oil reservoirs in the area. The original oil-in-place is estimated to be 15.9 × 106m3. Table 1 lists some of the reservoir rock and fluid properties. The reservoir has yielded more than 3.97 million m3 of oil from the Lower Mannville sand since its discovery in 1968. The field has been water flooded for more than nine years and water-cut has been increasing steadily since then. The pool now has 34 producers and four water injectors with a total injection rate of 3100 m3/d (19 500 bbl/d). Current oil production rate is approximately 650 m3/d (41 00 bbl/d) with an average water-cut of 80%. A previous water flood simulation stud y(1) and recent production logs indicated that there is a substantial volume of movable oil still in place. The study also showed that the existing waterflood has a good sweep efficiency in the bottom layers, but poorer in the upper layers due to the effects of gravity segregation, high vertical permeability and reservoir heterogeneity.