Polymer flooding is a well-established enhanced oil recovery (EOR) technique for mobility control. However, several factors affect a successful application of polymer at field-scale including injectivity and retention. The latter two parameters can lead to poor polymer performance. This work investigates the flow behavior of an HPAM-based polymer (SAV10) in carbonate reservoirs under high-temperature and high-salinity (HTHS) conditions. Formation water sample as well as three-outcrop carbonate cores were utilize in this work. Rheological studies and injectivity tests were conducted on SAV10 at two different temperatures of 20 °C and 90 °C. Polymer dynamic retention tests were also conducted to assess polymer loss in porous media.

The results showed that the HPAM-based polymer has a good tolerance to salinity with a shear thinning behavior at reservoir flow rates and shear thickening behavior at well flow rates under temperature condition of 25 °C. The rheological studies also showed that this viscoelastic behavior disappears at higher temperatures of 90 °C. From injectivity tests, with increasing flow rate, resistance factor increases at 25 °C and decreases at 90 °C, which is related to polymer rheological behavior and in particular in-situ viscosity. In addition, resistance factor at 90 °C was lower than that of 25 °C due to the decrease in SAV10 retention as temperature increases. This paper recommends the use of polymer taper prior to brine postflush to better characterize resistance factor as well as the removal of backpressure to better describe polymer degradation. The paper provides more insight into the applicability of synthetic polymers (SAV10) in reservoirs with harsh conditions. The study also helps in better understanding of polymer flow behavior for designing successful field projects.

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