Failure analysis of carbon dioxide corrosion through wet natural gas gathering pipelines

The aggressive behavior of carbon dioxide dissolved in water considers as one of basic reasons behind corrosion failure in oil and gas processes. Simulation study using HYSYS program employed to predict CO2 corrosion in natural gas gathering pipelines system. This work examines the effect of operating pressure, temperature, pH solution, pipeline length, flow regime, and pipe inclination on the CO2 corrosion. Based on the simulation results, following highlights were identified: increasing operating pressure results in increases CO2 partial pressure and promotes corrosion rate. Temperature affects formation of protective layer, where maximum CO2 corrosion rate reached 2.96 mm/year at 40 degrees C for this simulation conditions. After 40 degrees C, the protective layer consists and becomes more dense and reduces corrosion rate. In addition, lower pH enhances the solubility of carbonate, reduces participation rate, and enhancing CO2 corrosion. Dissolved CO2 concentration decreases along the pipeline length and the corrosion rate reduces as result. High velocity means efficient mixing which leads to prevent the formation of the protective layer and increases CO2 corrosion. Pipeline inclination affects the velocity of flow where positive elevation change reduces fluid velocity, while minus elevation change promotes fluid velocity. Frequently, these factors depend on each other and sharing the effects on the CO2 corrosion. The prevention of CO2 corrosion in natural gas gathering pipelines starts by understanding the effects of the operation conditions.