Polymer flooding is one of the most commonly employed improved oil-recovery techniques. However, its successful application is related to favorable reservoir conditions and geology. In addition, its application in high-temperature, high-salinity (HT-HS) carbonate reservoirs is still a challenging task. A series of laboratory core-flood experiments have been performed at reservoir conditions (temperature of 120 °C and salinity of 167 g/L) on carbonate outcrop core samples to evaluate the flow behavior of polymer injection. A baseline with continuous polymer injection is established initially, and the experimental data are then history-matched to generate the relative permeability curves for the process using commercial software. Various parameters including reservoir permeability, polymer-slug size, polymer initiation time, and flow rate are varied to determine the optimum flooding conditions. All of the simulation results are then revalidated with the experimental results. Encouraging results are obtained at the optimum conditions despite the mechanical degradation of the polymer, which shows up to 85% recovery of the original oil in place with manageable polymer adsorption on the rock surface. It is also observed that the potential polymer can work effectively on the core samples having moderate (30 mD) to high-permeability samples; however, the polymer loses its efficiency in lower-permeability rock samples. The results also indicate that early polymer injection helps to reduce the polymer-slug size required to reach residual oil saturation. The optimum conditions for polymer-slug size and polymer initiation time is 0.1 pore volume after 0.3 pore volume of water injection, respectively. The smaller polymer-slug size also helped to manage the resistance factor and the residual resistance values in the desirable range, i.e., 1.9 and 1.1, respectively. Identifying a polymer that can withstand high-temperature and high-salinity conditions in carbonate reservoirs will be a major step toward broadening the scope of successful polymer-flooding applications.

Polymer flooding is one of the most commonly used techniques to improve oil recovery; however its application is dependent on the technical and economic feasibility along with the knowledge of the risks involved. The presented work is focused on quantifying the uncertainties affecting the mobility of injected fluid in polymer flooding along with a sensitivity analysis of influential parameters. Initially, a coreflooding experiment on carbonate core sample is performed using partially hydrolyzed polyacrylamide, SAV 10 under high temperature high salinity conditions. The coreflood apparatus is aided with linear X-ray in order to record real time saturations for the entire length of core sample in addition to the pressure and production data. The experimental data are then history matched using commercial software to generate relative permeability curves and to optimize polymer slug size and initiation time. The optimized model is then used as a reference and a coredflood is conducted on the optimized conditions i.e. slug size and initiation time. The recovery obtained from the experimental run is compared with the simulation results. Polymer viscosity, adsorption on the rock surface and mechanical degradation are some of the other parameters included in the study. The optimum polymer flooding scenario established in this study is injection of 0.1 PV of polymer after 0.3 PV water injection. Encouraging results are obtained at the optimized conditions resulting in an overall recovery factor of 84% and early injection of polymer also helped to delay the breakthrough time. The small slug size resulted in low adsorption and residual residual factor for the optimized case is found to be 1.73.