Sweet (CO2) and sour (H2S) corrosion have continuously been a challenge in oil and gas production and transportation. Yet, some key issues are still not well understood, especially at high temperature production conditions. A CO2/H2S ratio of 500, which has been used (often inaccurately) to determine which corrosion mechanism is dominant, is probably even less valid at high temperature. The nature of the corrosion products forming at high temperature in CO2/H2S environments and their effects on the corrosion rate are not known. Finally, the impact on pipeline integrity of environmental changes between sweet and sour production conditions (simulating reservoir souring) has not been well documented. CO2, H2S, and CO2/H2S corrosion experiments were conducted at 120oC to investigate corrosion mechanisms and corrosion product layer formation at high temperature. The results show that the corrosion products were still clearly dominated by H2S under the pCO2/pH2S ratio of 550. Formation of Fe3O4, FeCO3, and FeS corrosion product layers had a direct impact on the measured corrosion rates and was dependent on the gas composition and on the sequence of exposure (CO2 then H2S and vice versa). Compared with H2S corrosion alone, the presence of CO2 could retard Fe3O4 formation in CO2/H2S mixture environment. No obvious change in steady state corrosion rate was observed when the corrosion environment was switched from CO2 to H2S and vice versa.