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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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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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51318-11223-Evaluation of Top-of-Line Corrosion Model for Multiphase Oil and Gas Environments

Product Number: 51318-11223-SG
Author: H. Li / K. M. Yap / S. Srinivasan
Publication Date: 2018
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The model was evaluated and effects of various parameters on corrosion rates are described. Corrosion rates obtained from the model are compared with actual field and lab testing data as a basis to quantify accuracy and efficacy.
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51316-7274-Inhibition Mechanisms for CO2 Corrosion Mitigation by Amines at the Top-of-the-Line

Product Number: 51316-7274-SG
ISBN: 7274 2016 CP
Author: Zineb Belarbi
Publication Date: 2016
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The principal objective of this work is to investigate and understand the TLC inhibition mechanism in the presence of diethylamine (DEA) and morpholine. In order to determine possible interactions between the tested amines and the steel surface, the surface charge was investigated by determining the potential of zero charge (PZC).
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51318-11117-Top-of-Line Corrosion Inhibiton and Proposal of an Inhibition Mechanism

Product Number: 51318-11117-SG
Author: Alyn Jenkins / Ian Gilbert / Aiman Kamaruzaman / Astrid Lone
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The work carried out to develop test methods suitable for assessing inhibitor performance in controlling TOL corrosion. New corrosion inhibitors have been developed that effectively mitigate TOL corrosion.
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