This paper reviews twenty-two polymer core flooding experiments performed in the laboratory on highly permeable (0.5 to 20 D) aged unconsolidated sandstone reservoir cores. Experiments were carried out at reservoir temperature, with oil viscosities ranging from 5 to 100 cP.

Polymer solutions were injected at different maturity levels: secondary (polymer injection at irreducible water saturation), early tertiary (after 0.5 to 1 PV of water injected), or late tertiary (after 20–80 pore volumes of water injected before polymer injection).

Final oil recovery results were analyzed as a function of maturity of the flood, but other parameters like permeability, wettability and polymer viscosity were also considered. For each experiment, history matching of oil and water production with differential pressure data including rate-bumps, constrained on in-situ saturation profiles enabled us to obtain robust relative permeability curves, and to differentiate ROS (remaining oil saturation at the end of experiment) and Sor (residual oil saturation, at kro=0).

Both the ROS vs. capillary number plot and the KR curves were more favorable for secondary or early tertiary polymerfloods than for late tertiary polymerfloods or waterfloods, especially at high water saturation. Residual oil saturations were lower when polymer was injected early.


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