Key Challenges for Internal Corrosion Modeling of Wet Gas Pipelines

The presence of CO2 and H2S in wet gas pipelines often creates the potential for high internal corrosion rates, which is typically mitigated by the injection of corrosion inhibitors. In practice, however, it is difficult to ensure that the inhibitor is always injected at the right level, while actual conditions in the pipeline may sometimes vary from those for which the inhibitor was qualified. Consequently, pipelines are also likely to be inspected from time to time using in-line-inspection tools. Various empirical and mechanistic models are used to estimate corrosion rates in such pipelines, both during the design phase to establish corrosion allowances and inhibitor availability requirements, and then during operation to help interpret inspection results and guide further operational decisions. These models can differ considerably in how they incorporate the effects of surface scaling, while the effects of inhibitors are generally not included in any mechanistic sense. This paper provides an overview of corrosion assessment for wet gas pipelines, with a particular focus on recent developments in modeling scale formation and the influence of inhibitors.