Experimental investigation of polymer injectivity and retention under harsh carbonate reservoir conditions

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 ATBS-based polymer in carbonate reservoirs under high-temperature and high-salinity (HTHS) conditions. Formation water sample as well as three carbonate cores were utilized in this work. Rheological studies and injectivity tests were conducted on the polymer at two different temperatures of 25 degrees C and 90 degrees C. Polymer dynamic retention tests were also conducted to assess polymer loss in porous media. The results showed that the polymer has a good tolerance to salinity with a shear thickening behavior within the injected flow rates under temperature condition of 25 degrees C. The in-situ rheological studies also showed that this viscoelastic behavior disappears at higher temperatures of 90 degrees C. From injectivity tests, with increasing flow rate, resistance factor increases at 25 degrees C and decreases at 90 degrees C, which is related to polymer rheological behavior and in particular in-situ viscosity. In addition, resistance factor at 90 degrees C was lower than that of 25 degrees C due to the decrease in polymer retention as temperature increases. The paper provides more insight into the applicability of an ATBS-based polymer in reservoirs under harsh conditions. The study also helps in better understanding polymer flow behavior for designing successful field projects.