Experimental Study on Corrosion Evaluation of P110SS Tubing in Carbonate Gas Reservoir Under Typical Operating Conditions

The carbonate gas reservoirs in the Sichuan Basin’s DY Formation present a highly aggressive HTHP (high-temperature/high-pressure) acidic environment containing hydrogen sulfide and carbon dioxide, posing severe corrosion risks to downhole tubular integrity. This study systematically investigated the corrosion behavior of P110SS tubing under simulated continuous service conditions using a custom-designed HTHP autoclave, replicating sequential operational phases including acidizing stimulation, flowback, and full-lifecycle production environments with varying temperature-pressure-corrosion (TPC) parameters. Through integrated analysis of weight loss measurements, SEM/EDS characterization, and 3D pitting morphology, gas-liquid phase interactions were elucidated. Results revealed gas-phase corrosion rates (13.75 mm/a) during acidizing surpassed liquid-phase rates (2.25 mm/a) due to FeCl₂·4H₂O and FeOCl formation via HCl volatilization. Flowback operations exhibited peak gas-phase pitting (7.72 mm/a) from inhibitor film breakdown, while residual acid accelerated liquid-phase pitting. Full-lifecycle assessment demonstrated cumulative corrosion severity hierarchy: acidizing > flowback > production. In gas-phase environments, the cumulative weight loss of tubing corrosion exhibits a decreasing trend with increasing temperature, which is attributed to the formation of protective Fe₃O₄/Fe₇S₈ films at elevated temperatures reducing gas-phase weight loss. These findings conclusively identify acidizing operations as the highest-risk operational phase, with gas-phase environments exhibiting significantly exacerbated P110SS tubing corrosion due to FeCl₂·4H₂O/FeOCl formation via HCl volatilization. These mechanistic understandings enable formulation of targeted protection protocols for high-H₂S/CO₂ carbonate reservoirs, addressing both uniform corrosion and localized pitting challenges.