T The rising demand for national oil and gas production presents a significant challenge as conventional oil reserves continue to decline. in response, efforts to optimize extraction from mature fields and technically complex reservoirs are becoming increasingly critical. one of the most promising tertiary recovery methods is enhanced oil recovery (eor), particularly polymer injection, which is designed to improve oil displacement efficiency by increasing the viscosity of the displacing fluid. despite its advantages, the application of polymer injection is often constrained by extreme reservoir conditions, such as high temperature and high salinity, which can lead to thermal and chemical degradation of polymer chains, reducing their effectiveness in maintaining mobility control and sweep efficiency. this study focuses on the screening and evaluation of the performance of two synthetic polymers, flopaam an 125 vhm and an 132 sh, for use in eor under harsh conditions. these polymers are partially hydrolyzed polyacrylamides (hpam) that are enhanced with atbs (2-acrylamido-2-methylpropane sulfonic acid) to improve their thermal stability and tolerance to salinity. the objective of this research is to determine which of the two polymers is more suitable for injection in reservoirs with temperatures up to 105°c and salinity levels of 36,000 ppm. the research methodology includes a series of laboratory tests designed to simulate reservoir conditions and measure the key performance indicators of the polymers. these tests include aqueous stability, rheological behavior, thermal resistance, filtration capability, and static adsorption. the aqueous stability tests demonstrated that both polymers remained visually stable and clear over a period of 7 days at room temperature and 105°c, indicating compatibility with injection water and resistance to immediate degradation or precipitation. rheological analysis, conducted using a brookfield rheometer at reservoir temperature, revealed that an 132 sh achieved the target viscosity of 6.7 cp at a concentration of 2500 ppm, while an 125 vhm achieved it at a lower concentration of 2000 ppm. this implies that an 125 vhm may offer a cost advantage due to its effectiveness at a lower dosage. thermal aging tests, conducted over a 60-day period, showed that both polymers maintained their viscosity without significant degradation when stored in closed ampoules at 105°c. the filtration tests produced filtration ratio (fr) values of 1.00 for an 125 vhm and 1.06 for an 132 sh, both within the acceptable limit (fr < 1.2), suggesting both polymers could effectively pass through porous media without causing injectivity issues or formation damage. adsorption tests revealed a significant difference between the two polymers. an 125 vhm exhibited a lower adsorption value of 505 µg/g compared to an 132 sh, which adsorbed up to 810 µg/g on core surfaces. this indicates that an 125 vhm would experience less polymer loss due to rock-fluid interactions, making it more efficient in maintaining concentration throughout the injection path. based on the collective results from all tests, it is concluded that flopaam an 125 vhm at a concentration of 2000 ppm is the most suitable polymer for application in high-temperature and high-salinity reservoirs. it offers sufficient viscosity, high thermal and aqueous stability, effective injectivity, and lower adsorption loss. this makes it not only technically feasible but potentially more economical for field-scale polymer flooding applications. the findings are expected to support further optimization of chemical eor strategies in indonesian oil fields and similar reservoirs globally.