Abstract

About half of world oil production results from waterflooding. The remaining resources, however, are more viscous and less amenable to waterflood as conventional oil reserves are produced. In offshore and Arctic environments improved methods of cold production for viscous oil are needed because the introduction of heat to thin viscous oil appears to be unlikely. Unfavorable mobility ratio and sweep is modified by use of polymer solutions. Of the various EOR polymer formulations, newly developed associative polymers show special promise. We investigate pore and pore network scales because polymer solutions ultimately flow through the pore space of rock to displace oil. We conduct and monitor optically water/oil and polymer solution/oil displacements in a two-dimensional etched-silicon micromodel. The micromodel has the geometrical and topological characteristics of sandstone. Conventional hydrolyzed polyacrylamide solutions and newly developed associative polymer solutions with concentrations ranging from 500 ppm to 2500 ppm were tested. The crude oil had a viscosity of 210 cP at test conditions. Our results provide new insight regarding the ability of polymer to stabilize multiphase flow. At zero and low polymer concentrations, relatively long and wide fingers of injectant developed, leading to early water breakthrough and low recoveries. At increased polymer concentration, a much greater number of relatively fine fingers formed. The width to length ratio of these fingers was quite small and the absolute length of fingers decreased. At a larger scale of observation, the displacement front appears to be stabilized; hence, recovery efficiency improved remarkably. Above a concentration of 1500 ppm, plugging of the micromodel by polymer and lower oil recovery was observed for both polymer types. For tertiary polymer injection that begins at breakthrough of water, the severe fingers resulting from water injection are modified significantly. Fingers become wider and grow in the direction normal to flow as polymer solution replaces water. Apparently, improved sweep efficiency of viscous oils is possible (at this scale of investigation) even after water flooding. The associative and conventional polymer solutions improved oil recovery by about the same amount. The associative polymers, however, showed more stable fronts in comparison to conventional polymer solutions.

Introduction

Effective polymers for high salinity environments and chemical costs are major concerns when modifying the viscosity characteristics of aqueous injectants for oil recovery. So-called associative polymers have been tested in this study. The term associative polymer is a broad classification (Glass, 2000). Here, we refer to water-soluble associative polymers that have undergone some hydrophobic modification so that they contain both water-soluble (hydrophilic) and water-insoluble components of varying levels of hydrophobicity. Associative polymers possess a unique thickening mechanism and most are environmentally benign. Broadly speaking, polymer networks form in solution and consist of intra- and inter-molecular hydrophobic junctions (Tripathi et al., 2006). These polymers hold the promise of high resistance against salinity and greater in-situ viscosities (Fig.1) in comparison to conventional polymers at similar concentrations.

Buckley and Leverett displacement theory (Lake, 1989) assumes that water displaces oil with a piston-like shock followed by a rarefacting water saturation. Viscous fingers, however, are common features of unstable displacements where water is more mobile than oil. In general, viscous fingers refer to the onset and evolution of instabilities that evolve during the displacement of fluids in a porous system. Most often instabilities are linked to mobility differences between phases. Because mobility is inversely related to phase viscosity, viscous structures typically consist of fingers invading into the displaced fluid and propagating through the porous medium and leaving clusters of the displaced fluid behind. Clearly, heterogeneities in rock exacerbate unstable displacement.

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