Lesson learned on 20 years of challenges to internal corrosion protection of subsea pipelines– Corrosion inhibitor or pH stabilization?
Reza Ghorbani
Reza Ghorbani, Omid Razavi Zadeh
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The three phase fluid of the massive South Pars reservoir under the Persian Gulf, is transmitted 100Km to onshore facilities via numerous 32” API 5L pipelines. The wet sour fluid contains 0.5 mol% of H2S and 1.7 mol% of CO2 which forms a hostile environment to carbon steel. Hence, as per former laboratory researches at design stage in about 20 years ago, two different mitigation methods were concluded to tackle internal corrosion and hydrate formation.

The primary method was pH stabilization that was implemented originally for the first time in the industry by TOTAL company; and the second one was conventional injection of film forming corrosion inhibitor. Since then, pH stabilization has been carried out by continuous injection of 70 wt.% Lean Mono Ethylen Glycol and 4wt.% of Methyl DiEthanol Amine, as the main method. In the meantime, film forming inhibitor injection was also employed as the backup method to compare the pros and cons of both techniques.

The pH stabilization technique requires a robust MEG regeneration unit and when the fluid is enriched with calcium and carbonate ions during water formation influx, it can lead to sever scale deposition and clogging the line. On the other hand, corrosion inhibition by film forming has some ambiguities such as protection of metal beneath the sludge, or the reliability of residual corrosion inhibitor in the presence of Low dosages of kinetic hydrate inhibitor.

In this report, mass spectrometry and high pressure liquid chromatography on field and synthetic samples is deployed to pinpoint the actual error value and compensation rate. Consequently, a reasonable degree of certainly for the amount of residual corrosion inhibitor is figured out to increase the reliability in the pipeline integrity management strategies.

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