Chemical flooding in high-temperature, high-salinity and low-permeability carbonate reservoirs is faced with problems such as reduced chemical activity, poor stability and difficult chemical injection, which brings uncertainty to oil displacement effectiveness. The study conducted experiments on interfacial tension, contact angle, viscosity, core injection performance, and core oil displacement by chemicals. It identified the surfactant and polymer suitable for harsh environments, clarified the injection limits of polymers, and compared the oil displacement performance of different chemical systems. Ultimately, the optimal chemical flooding system and method for high-temperature, high-salinity and low-permeability carbonate reservoirs is revealed. The results demonstrate that amphoteric surfactants exhibit superior thermal and salt resistance. Under 78°C and 94,148.0 mg/L, 225068.0mg/L salt water condition, EAB solution with a concentration of 3,000 mg/L could effectively reduce the interfacial tension to 0.006 mN/m and 0.001 mN/m, respectively. Comparative studies of various amphoteric surfactants revealed that interfacial tension decreases with increasing carbon chain length. It indicates a fact that enhancing hydrophobic affinity proves to be an effective strategy for developing ultra-low interfacial tension amphoteric surfactants. Conventional HPAM shows poor long-term stability at 78℃, 94148.0 mg/L, and 225068.0mg/L salt water environment, with viscosity retention rate below 5% after 50 days of aging. In contrast, SAV10 and SAV55 polymers demonstrate better stability, maintaining viscosity retention rates above 80% and 60% respectively after 90 days of aging. In a 3.4×10-3 μm2 core, the SAV10 injection pressure gradient showed continuous elevation without stabilization, making the polymer injection difficult. In a 9.6×10-3μm2 core, SAV10 with concentration ≤200mg/L(0.81mPa·s) the injection pressure gradient stabilized finally, showing certain injection capability. In a 21.0×10-3 μm2 core, polymer with concentration ≤1000mg/L(≤2.8mPa·s) achieved good stability in injection pressure gradient and successful injection. The oil displacements in cores with permeabilities about 10.0×10-3 μm2 demonstrates that single surfactant injection shows limited recovery enhancement: 4.4% increase with 0.3PV injection and 8.1% with 1.0PV injection. Polymer flooding achieves improved oil recovery enhancement of 16.4%. The surfactant foam system demonstrates synergistic effects of ultra-low interfacial tension and sweep-volume enlargement by pressure increase, delivering a peak recovery increment of 27.4%. The SP composite system follows with 24.0% recovery enhancement.