Rock-Fluid Interaction During Low-Salinity Polymer Flow in Porous Media

Abstract

Usually, oil fields are developed over three stages. First is the primary oil recovery, where the natural underground pressure is used to drive the oil to the surface. Afterwards is the secondary oil recovery, usually by water flooding or gas injection. However, the water flood yields lower sweep efficiency in heterogeneous reservoirs, contrary to homogeneous reservoirs. Tertiary flooding methods are applied to increase the oil sweep efficiency, hereby improving the efficiency of the extraction process. These methods include injection of gas and chemical solutions. This study focusses on the polymer flooding method. Polymers are used to adjust the mobility ratio (M) between oil and the displacing fluid, where the viscosity of the displacing fluid is increased significantly. However, rock-fluid interaction might affect the viscosity of the polymer, which in turn affects the mobility ratio.
A series of core flood experiments were conducted, where rock-fluid interaction likely affects the viscosity of the polymer. Hydrolyzed polyacrylamide (HPAM) is used as the polymer, which is injected in a sandstone core with brine. The produced fluids are analyzed afterwards, where its ion concentration, rheology, pH, and carbon content are measured. The results of the effluent analysis shows no change in viscosity compared to the injected polymer. There is however, a decrease in the divalent cations in the Low-salinity fluids, which can be explained by these cations getting stripped from the fluid at attaching to the rock surface. An increase in the effluent High-Salinity Brine is observed, which may be the cause of mechanical degradation, or by the influence of dissolved Ca2+ or Mg2+ cations due to leaching.