A polymer flooding mechanism for mature oil fields: Laboratory measurements and field results interpretation

Abstract

Although polymer flooding has been widely studied in the literature on oil recovery, many questions remain about the technique's action mechanisms. It is widely accepted that the process is based on increasing viscosity of the aqueous phase (injected fluid). The polymer can also act secondarily by reducing the relative permeability to water. Fields that are markedly heterogeneous, highly depleted or that contain fluids with strong salinity are not good candidates for the process. To overcome these restrictions, the most recent applications have used more resistant polymers, with higher molar masses, injected in larger quantities, to preserve the level of viscosity under these adverse conditions. However, a pilot test in a field under adverse conditions showed surprising results and unexpected pressure abnormality, even with small quantities of partially hydrolyzed polyacrylamide (HPAM) with relatively low molar mass (6 × 106 g/mol). This paper reports the investigation of the prevailing mechanism responsible for these unexpected results, by means of laboratory tests of flow in porous media and rheological analysis of fluids and hydrodynamic diameter of polymer molecules. The Salt effect (NaCl) on polymer solutions was researched by rheology and particle size analysis at 25 and 50 °C. The results showed that mechanical/hydrodynamic retention prevails over polymer adsorption at the rock, with the former being caused by the increase in the polymeric hydrodynamic volume in fluid dilution processes. Besides this, increased temperature was found to favor greater hydrodynamic volume under tested conditions, while salinity had little influence. The results also shed new light on the flow behavior of polymer solutions in porous media, particularly in polymer injection for enhanced oil recovery from mature fields.