<p>Addressing the failure of tubing string breakage and disengagement in an operating ultra-deep well A, this paper describes the analysis of the corrosion failure mechanism of the tubing from multiple perspectives including macroscopic morphology, physicochemical properties, and service environment. Through macro-fracture observation, hardness and metallographic structure testing, corrosion product composition and phase analysis (SEM-EDS/XRD), and mechanical property testing of the failed sections, combined with actual operating conditions such as downhole temperature, pressure, corrosion medium composition, and structural parameters, a comprehensive evaluation system for tubing failure was established. Results indicate that the tubing’s physicochemical properties and metallographic structure comply with API 5CT-2011 standards, suggesting that material composition is not the primary failure factor. However, under service conditions characterized by high Cl⁻ concentration, elevated temperature and pressure, and coexisting H₂S-CO₂, severe localized and crevice corrosion occurred on the tubing’s inner wall. Corrosion products primarily comprised FeS₂, Fe₇S₈, FeCO₃, and CaSO₄, revealing typical H₂S-CO₂ synergistic corrosion characteristics. Residual acid solution during acid pressure operations further accelerated corrosion rates. Experimental simulations indicated an average corrosion rate of 6.86&#xa0;mm/a, with localized rates exceeding 50&#xa0;mm/a. Corrosion-induced wall thinning and pitting in high tensile stress concentration zones triggered stress corrosion cracking propagation, ultimately leading to ductile fracture of the tubing. This study elucidates the failure evolution mechanism of ultra-deep well tubing under combined acidizing fluid and H₂S-CO₂ environments, providing critical technical support for corrosion-resistant material selection, acidizing process optimization, and string integrity management in similar well conditions.</p>