Workflows to assess the technical and economic suitability of an enhanced oil recovery (EOR) technique for a particular field generally involve laboratory testing, such as core flooding experiments, and field-scale reservoir modelling. When building these field scale models and interpreting laboratory experiments it is important to understand the flow properties of all phases present in the particular EOR process. In alkaline-surfactant-polymer flooding (ASP) flooding, surface-active molecules decrease the interfacial tension between water and crude oil, increasing the capillary number, and recovering oil trapped in the reservoir pores. The ultra-low interfacial tensions needed for ASP flooding occur when the surface active molecules are equally soluble in the brine and oil phases. Under these conditions, in addition to the brine and oil phases, a third thermodynamically stable phase is formed. This third phase is known as a microemulsion. While the flow properties of crude oil and polymer-enriched brine are well understood, little has been done to characterize the microemulsion phase, particularly with respect to rheology in porous media. In this study, larger volumes of microemulsion, with and without polymer, are generated using a model ASP system. These microemulsions are studied using conventional shear rheology. Additionally, an in situ, or apparent, viscosity is recovered from core flooding experiments in Berea sandstone, where pressure drop across the core is recorded as a function of the flow rate of the microemulsion through the core. The implication of these results for ASP flooding is discussed.


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