Summary Carbon dioxide (CO2) corrosion remains a critical threat to production tubing integrity in high-temperature, high-pressure (HTHP) gas wells, where accurate service life prediction continues to challenge the industry. This study establishes an improved corrosion rate model through laboratory experiments under coupled temperature-pressure conditions. The model employs a polynomial representation that achieves higher predictive accuracy than conventional methods under varied operational conditions. Furthermore, a service life prediction framework has been developed that incorporates triaxial stress distribution and temperature-dependent material degradation, providing a more realistic assessment of production tubing performance under actual service conditions. Validation with field measurements confirms a strong agreement between predictions and observed data. Sensitivity analysis reveals complex nonlinear relationships between key parameters and corrosion behavior, with the most vulnerable sections identified at a 200–900-m depth. This work provides both methodological advances and practical guidance for tubing design and integrity management in HTHP environments.
Zhao et al. (2026) studied this question.