A Mechanistic Model for Predicting Top‐of‐the‐Line Corrosion in CO ₂ /H ₂ S Environments: Validation and Field Application

ABSTRACT This study develops a mechanistic model to predict top‐of‐the‐line corrosion (TLC) in wet natural gas pipelines under sweet (CO₂) and sour (CO₂/H₂S) conditions. The framework incorporates water condensation, CO₂–H₂S–organic acid aqueous speciation, electrochemical kinetics, and corrosion product film formation, emphasizing rapid FeS precipitation in sour service. The proposed sour model reproduced published laboratory data with a mean absolute deviation < 45% across gas compositions (:2‐10 bar, :0‐2 bar), wall temperatures (15°C–75°C), condensation rates (0.002–0.25 ml/m²·s), and organic acid concentrations (0–1300 ppm), while the deviation for sweet service was < 16%. The sour TLC model applied to two offshore sour natural gas transmission pipelines showed strong agreement with in‐line inspection data. Field simulations indicate that the highest sour TLC rates occur at steel surface temperatures of 20°C–35°C, with a maximum corrosion rate of 0.9 mm/year. High condensation rates alone do not cause TLC; significant corrosion can occur even at low condensation rates (0.00002–0.15 g/m²·s). This work establishes one of the first unified mechanistic framework for predicting sour TLC.