Application of polymer flooding technique under extreme reservoir conditions (~120°C and 167000 ppm) is still of great concern. In high temperature and high salinity (HTHS) reservoirs, the commonly used polymers for improved oil recovery purposes are ineffective due to chemical degradation and poor injectivity. Therefore, the aim of this paper is to screen partially hydrolyzed polyacrylamide (HPAM) base polymers in order to find suitable polymer for a targeted HTHS carbonate reservoirs. Polymer screening study was carried out on three new NVP-HPAM base polymers to identify a potential candidate which can withstand harsh reservoir conditions. Initially, a comprehensive rheological study was conducted at various polymer concentrations (1000-4000 ppm) and brine salinities to investigate the effectiveness of the polymers. Then, thermal stability test was conducted at anaerobic condition and 120°C for three months. Finally, injectivity test was conducted with the best polymer and in the absence of oil at 120°C and formation salinity (167000 ppm). The experiment was done by sequential injection of 3 polymer concentrations (3000, 1500, and 750 ppm). Parameters such as resistance factor, residual resistance factor, insitu rheology, and apparent shear rates were investigated during the experiment. Results from the rheometric studies showed that all three polymers have acceptable initial viscosifying properties at ambient temperature and shear thinning behaviors within shear rate range of 1-100 s -1 . The results also indicated that polymer viscosities dropped with increase in temperature and salinity. However, they still showed good resistance up to 167000 ppm and 120°C. The thermal stability test for the potential polymer showed better stability and retained more than 90% of its initial viscosity after the ageing period. Whilst injecting at 3000 ppm, the resistance factor (RF) was between 20-10 (at different flowrates). During 1500 ppm and 750 ppm, the RF were in the range of 14-6.5 and 5-2.7 respectively. At low flowrates (0.05-1.0 cc/min) of polymer injection, shear thinning behavior was observed. Whereas, shear thickening behavior at high flowrates was observed at all concentrations. Finally, the residual resistance factor (RRF) recorded for the injectivity experiment was found to be 6.17. The potential polymer showed promising results for its application in heterogeneous carbonate reservoir with higher temperature and salinity of 120°C and 167,000 ppm respectively. The study also leads to better understanding of polymer flow behavior in high temperature high salinity carbonate reservoirs.