Large diameter subsea pipelines operating mainly in stratified flow are being used across the world for wet gas transportation over significant distances from offshore fields to onshore facilities. Understanding corrosion mechanism occurring at the top of the line under dewing conditions is a key component of operations corrosion management strategy to ensure long-term pipeline integrity. The challenge in predicting corrosion in sour systems is due to the varied nature of iron sulfide scales formed over the expected subsea pipeline temperature ranges and condensation rates that result in different corrosion mechanisms. Current industry practice is to use sweet corrosion prediction methodologies to establish the risk of top of line corrosion in sour systems. This paper will demonstrate through field validated laboratory results that this approach may be inadequate and propose operational practices to manage the risk of top of line corrosion in large diameter subsea wet gas pipelines.


Top-of-the Line (TOL) corrosion can occur in wet gas pipelines operating in stratified flow. This corrosion phenomenon occurs when low pH water--devoid of inhibitors that are usually present in the bottom of the line fluids--condenses on the upper half of the pipeline causing severe corrosion. The first TOL corrosion report dates back to the 1960's at the sour Lacq field in France1. It occurred in low velocity lines with stratified or stratified-wavy flow regimes. The second reported case was in the sour Crossfield pipelines where again TOL corrosion occurred in lines with low velocities and stratified-wavy flow regime2. At high flow rates, corrosion inhibitor and condensate present in the bottom of the line can be transported to the top of the line, providing inhibition of TOL corrosion. Although these first reported cases of TOL corrosion were in sour fields, sour TOL corrosion has historically been treated as a sweet corrosion phenomenon. Sweet TOL corrosion has been investigated extensively in the literature and several models have been developed to predict its occurrence3, 4, 5, 6, 7. These models are based on the formation of a protective FeCO3 film at the TOL. Sweet TOL corrosion is therefore limited by the amount of iron that can be dissolved in the condensing water. The initial pH of the solution at the TOL will depend on the partial pressure of CO2 and the presence of volatile organic acids in the gas stream. As iron is dissolved in the condensing phase, the pH increases and leads to the possibility of protective iron carbonate formation. At low condensation rate, the accumulation of iron in the TOL solution will increase the pH and result in the formation of protective iron carbonate scale. At high condensation rates, the dissolved iron is continuously removed. This leads to a lower TOL solution pH and instability of iron carbonate scale, resulting in higher TOL corrosion rate. Thus, in sweet systems a critical condensation rate can be predicted below which TOL corrosion should not be significant. The critical condensation rate has been estimated to be between 0.15 g/m2s and 0.25 g/m.

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