Corrosion Mechanisms and Rate Prediction for Gas Well Tubing in Sour Environments under Combined H2S/CO2 Corrosion

Summary As a major high-sulfur natural gas province in China, the Sichuan Basin frequently experiences severe tubing corrosion in producing wells due to the coexistence of H2S and CO2. Especially in high-temperature, high-pressure gas reservoirs with medium concentrations of H2S/CO2, such as the M Block in central Sichuan, corrosion-induced tubing failure and wellbore plugging have severely affected the long-term safe production and economic development of gas wells. Despite extensive studies on single-gas corrosion and mixed-corrosive environments, reliable models that accurately predict the H2S-CO2 synergistic corrosion rate under representative wellbore conditions remain scarce. To this end, this study takes the MX-X11 well in the M block as a case example. First, through wall thickness measurements of the entire well section of the tubing, combined with X-ray diffraction (XRD), X-ray fluorescence (XRF), scanning electron microscopy (SEM), and energy-dispersive spectroscopy (EDS), the corrosion mechanism of the tubing under the synergistic effect of H2S and CO2 was analyzed. Subsequently, a semiempirical corrosion rate prediction model considering temperature-pressure coupling was established, and the influencing factors of corrosion were simulated and analyzed. On this basis, a corrosion rate prediction model is developed and integrated with coupled temperature-pressure profiles to enable corrosion prediction along the wellbore. The results demonstrate that the tubing corrosion rate exhibits strong depth dependence. Corrosion products vary systematically with depth, indicating distinct corrosion regimes. In shallow intervals, corrosion products are dominated by FeS2, indicating an H2S-dominated environment. In deeper intervals, the products progressively shift to FeCO3, accompanied by FeS and Fe3O4, suggesting an increasing contribution from CO2-driven corrosion. By quantifying the synergistic effects of H2S and CO2 partial pressures, a corrosion rate prediction model incorporating both gases’ partial pressure terms is established. The model captures corrosion behavior across a wide range of partial pressure conditions and yields corrosion rate profiles that are generally consistent with field-derived average corrosion rates from the MX-X11 well. In addition, the proposed corrosion rate model is coupled with a tubing temperature-pressure model to simulate corrosion behavior under different operating conditions. Temperature exerts a pronounced effect on corrosion rate: The rate is low at lower temperatures, increases with temperature, and is suppressed at higher temperatures due to the formation of a dense corrosion product film. With respect to gas partial pressures, the interaction between H2S and CO2 significantly affects the corrosion rate. Different partial pressure ratios promote corrosion product films with different compositions, thereby modifying corrosion kinetics. These findings provide a scientific basis for predicting tubing corrosion in the M Block of the Sichuan Basin and in comparable sour gas reservoirs, supporting full life cycle corrosion management of tubing systems. Further optimization and independent validation of the proposed model using additional wells will enable more robust guidance for corrosion mitigation in oil and gas fields. It should be noted that the corrosion rate prediction model proposed in this study is primarily applicable to the prediction of uniform corrosion rates. For the evaluation of localized pitting corrosion in practical engineering, pitting depth measurements should still be incorporated.