Corrosion failure of subsea pipelines and identification model for internal corrosion risk zones

There are abundant oil and gas resources in the ocean, and its average reserves are far more than those on the land. However, it is difficult to detect the internal parts of submarine pipelines, with high investment capital and high risk. After detecting the internal parts of 4 submarine pipelines in Block A4 of L gas field, it was found that G2 pipeline had the largest corrosion defect depth, which accounted for 36 % of the pipe wall thickness. This study has established a model for identifying the internal corrosion risk areas of pipelines, which takes into account different pipeline inclination angles, flow rates and Cl⁻ concentrations. Through the simulation loop experiment and by means of electrochemistry, the corrosion rates of pipelines with different inclination angles under different temperatures, Cl⁻ concentrations and flow rates are studied. A hydrochemical model of the non-ideal CO₂-solution system was constructed based on the Peng-Robinson (PR) equation and the Pitzer model. Subsequently, coefficients of flow rate and Cl⁻ concentration are incorporated, leading to the establishment of a model for identifying the internal CO₂ corrosion risk regions within submarine pipelines. This model is validated in conjunction with experimental data, achieving an accuracy rate surpassing 80 %. Additionally, by integrating the on-site operational conditions of the pipelines, the regions susceptible to internal corrosion in submarine pipelines are pinpointed, and the high-risk zones and the parts liable to perforation within the A4-G2 pipeline are precisely determined. This research holds significant theoretical and practical implications for safeguarding the safe operation of submarine natural gas transmission pipelines.