Abstract
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.
