This study investigates the integrity of a 16″ onshore pipeline in North-East Thailand, which unexpectedly exhibited significant external corrosion despite being equipped with dual protective systems—FBE coating and ICCP. Initial assumptions based on MFL pig inspections of two 10″ pipelines indicated a minimal corrosion threat, aligning with simulated inhibited corrosion rates. However, the 2021 MFL inspection of the 16″ pipeline revealed 2,265 external metal loss features at 1,266 locations, with corrosion depths reaching up to 30% of the nominal thickness, particularly around FJC.

Direct assessments confirmed the accuracy of MFL data, revealing that improper FJC application during installation and CP shield effects were significant factors in the corrosion observed. The investigation also highlighted the limitations of routine CIPS and DCVG surveys in detecting these issues. A new FJC repair system was qualified, and repair methodologies were refined, resulting in over 40% productivity improvement and zero incident cases from 2021 to 2024. This study underscores the importance of regular inspection, maintenance, and the development of robust repair strategies in managing the integrity of aging pipelines. The findings contribute to the field of pipeline corrosion management and offer practical solutions for similar challenges.

Keywords:
riser corrosion, materials and corrosion, corrosion management, subsurface corrosion, pipeline corrosion, h2s management, production chemistry, assessment, growth rate, inspection
Subjects:
Production Chemistry, Metallurgy and Biology, Pipelines, Flowlines and Risers, Materials and corrosion, Well Integrity, Subsurface corrosion (tubing, casing, completion equipment, conductor), Corrosion inhibition and management (including H2S and CO2)
Copyright 2024, Society of Petroleum Engineers DOI 10.2118/222744-MS
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