Chemical Enhanced Oil Recovery (cEOR) flooding is one of the more attractive methods to improve oil recovery. However, during times of instability in the oil market, cost of specialized chemicals and necessary facilities for alkali-surfactant-polymer (ASP) or surfactant-polymer (SP) make this technology very expensive and challenging to implement in the field. In majority of cases, polymer flooding alone has proven to be the most cost-effective solution that has resulted in attractive and predictable return on investment. In recent times, challenging economic environment has operators looking for added economic and sustainable savings. The possibility of re-injection of produced polymer to offset injection concentration requirements can lead to reduced cost and longer sustainability of oil recovery; thus, offering a subsequent reduction in produced water treatment and a reduced full-cycle carbon footprint. This innovative approach is subject to conditions experienced in the surface facilities, as well as in the reservoir. As part of this study, different polymer chemistries were investigated for their mobility control in porous media and comparative effect on oil recovery trends in presence of produced fluid containing residual polymer. The initial fluid-fluid testing and lab characterization results were validated against a mature field EOR project for reduction in polymer requirement to achieve target viscosity. Monophasic flow behavior experiments were performed in Bentheimer and Berea outcrop cores, while oil recovery experiments were performed in Bentheimer outcrops with different polymer solutions – freshly made and combinations with residual produced polymer. In addition, comparative injectivity experiments with field and lab prepared solutions were performed in Bentheimer outcrop cores. Based on field observations and lab measurements, a 10-15% reduction in fresh polymer loading could be achieved through the re-utilization of water containing residual polymer in these specific field conditions. Similar screen factor measurements were obtained with increasing concentration of residual polymer solution. This agreed with the monophasic injectivity experiments in both outcrop cores that resulted in similar resistance factors for fresh polymer and blends with produced water containing residual polymer solution. Oil recovery experiments also resulted in similar oil displacement behavior (approximately 30-40% OOIP after 0.5 PV waterflood) for fresh and blends with sheared polymer solutions, validating no loss in recovery potential, with the added benefit of 10-15% polymer loading reduction.

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