Understanding Geometric Control of Water Film and Shear Stress in Gas–Liquid Flow for Corrosion Prediction in Natural Gas Pipeline

This study examines the corrosion behavior of natural gas pipelines through electrolyte-based simulations and computational fluid dynamics (CFD) modeling of gas–liquid multiphase flow, focusing on the synergistic effects of hydrogen sulfide (H₂S) and carbon dioxide (CO₂) in aqueous environments. Corrosion initiates at a water concentration of 1250 mg L⁻¹ under 40 kg cm⁻² pressure, decreasing to 1000 mg L⁻¹ as pressure increases to 200 kg cm⁻². Elevated pressure enhances electrochemical activity, gas solubility, and acidity, thereby intensifying corrosion. At lower H₂S levels, the formation of a protective iron sulfide (FeS) layer stabilizes the pH and reduces corrosion rates, whereas temperatures exceeding 30 °C compromise the protective integrity of both FeS and iron carbonate (FeCO₃) films. CFD results reveal that corrosion severity is influenced by hydrodynamic conditions, particularly in regions with thin water films and high shear stress. In horizontal pipelines, the 60° elbow exhibits the thickest water film (55 µm) and highest shear stress (~13 Pa), followed by the 90° (54 µm, ~13 Pa) and 30° elbows (52.2 µm, 9.57–11.0 Pa), whereas straight sections maintain significantly thinner films (0.11–1.10 µm). In the vertical plane, the 45° elbow demonstrates the greatest corrosion susceptibility, with the thickest water film (68.6 µm) and shear stress (~15 Pa). Overall, elevated pressure, temperature, and flow turbulence promote localized corrosion by enhancing gas dissolution and disrupting protective surface films.