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Prediction And Mitigation Of Top Of Line Corrosion Risk Due To Damages In External Pipeline Coating

Picture for Prediction And Mitigation Of Top Of Line Corrosion Risk Due To Damages In External Pipeline Coating
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A visual inspection of a subsea field development, transporting wet gas, containing approximately 1.5 to 2 mol% of CO2 to shore, was conducted via ROV (remotely operated vehicle). The pipeline system is largely carbon steel with only short lengths of CRA (corrosion resistant alloy) piping from the wellhead to the production/pigging manifold. Downstream of the pigging manifold the system has 20” carbon steel spools leading to the FTA (flowline termination assembly) and then 20” carbon steel flowlines to the riser platform.

Product Number: 51321-16789-SG
Author: Marc Singer, Nick Bardsley, Julie Morgan, Stuart Kegg, Adam Darwin, Peter Cossins, Anthony Kwong, Jason Biddlecombe, Jo Yetman, Joe Bullen
Publication Date: 2021
Industries: Coatings and Linings , Corrosion Monitoring and Control , Coatings
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$20.00

This paper presents the methodology adopted to evaluate the effect of external insulation damage on TLC within carbon steel flowlines. A field development, consisting of subsea wells in 830 m water depth, transports wet gas via two 20” diameter production flowlines. The wet gas contains about 1.5 to 2 mol% CO2. The pipeline system is largely carbon steel with only short lengths made of CRA piping. Lean MEG mixed with corrosion inhibitor is injected at the wellheads for hydrate inhibition. A subsea remotely operated vehicle inspection of the deep water 20” spools
revealed insulation damage and bulging. These damages could act as cold spots and lead to enhanced water condensation and TLC on the internal wall of the flowlines. In order to assess the severity of the impact of the damages, a thermal Finite Element Analysis step was undertaken to determine the condensation rates on the inside of the lines. The corresponding TLC rates were then calculated using mechanistic corrosion prediction software considering multiple production conditions. The corrosion assessment helped identify which insulation damages required
remedial actions. The TLC rates calculated were later verified by internal pipeline pigging inspection.

This paper presents the methodology adopted to evaluate the effect of external insulation damage on TLC within carbon steel flowlines. A field development, consisting of subsea wells in 830 m water depth, transports wet gas via two 20” diameter production flowlines. The wet gas contains about 1.5 to 2 mol% CO2. The pipeline system is largely carbon steel with only short lengths made of CRA piping. Lean MEG mixed with corrosion inhibitor is injected at the wellheads for hydrate inhibition. A subsea remotely operated vehicle inspection of the deep water 20” spools
revealed insulation damage and bulging. These damages could act as cold spots and lead to enhanced water condensation and TLC on the internal wall of the flowlines. In order to assess the severity of the impact of the damages, a thermal Finite Element Analysis step was undertaken to determine the condensation rates on the inside of the lines. The corresponding TLC rates were then calculated using mechanistic corrosion prediction software considering multiple production conditions. The corrosion assessment helped identify which insulation damages required
remedial actions. The TLC rates calculated were later verified by internal pipeline pigging inspection.

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