This paper presents laboratory polymer core floods in secondary and tertiary mode carried out on highly permeable aged sandstone reservoir cores at reservoir temperature, with oil viscosities ranging from 7 (reservoir A) to 55 cP (reservoir B). Oil recovery is measured through three redundant techniques: mass balance, X-Ray saturation and miscible tracer test. Experimental results are interpreted to obtain polymer relative permeability curves by history matching oil production profiles, differential pressure and in-situ water saturation profiles at every step of the experiments.
The main results can be summarized in three points. Small scale heterogeneity and core quality have a large impact on the experimental results, making the comparison between different floods cumbersome, as well as between water flood and polymer flood. Polymer injection in this oil-wet high permeability reservoir changes the balance between capillary and viscous forces, leading to oil recovery in layers where capillary trapping is observed during water injection. Finally, there seems to be a difference in behavior between secondary and tertiary polymer floods, where the local residual saturation to polymer injection, as quantified by X-ray, is lower in secondary mode than in tertiary mode, while in tertiary mode both water and polymer injection have the same local residual oil saturation. Possible reasons as to why secondary polymer injection behaves differently than tertiary polymer injection are still being investigated.