Corrosion within an amine gas-treating plant is problematic because it can result in unscheduled breakdowns and outages. Free acid gas and high temperatures, among other reasons, are often cited as significant corrosion failures in amine units.

In refineries, amine systems suffer from corrosion by carbon dioxide (CO2) and hydrogen sulfide (H2S), strong acids, contaminant byproduct (e.g., amine heat stable salts, and amine degradation products, which can accumulate in certain parts of the refinery amine system. Amine plant operational problems, (e.g., excessive foaming, corrosion and capacity reduction) are often attributed to the accumulation of amine HSS. Due to its high foaming characteristics, substantial amine loss has been observed in the operation of these units.

In the overhead systems, a buildup of high concentrations of H2S, CO2, nitrogen compounds, and acids can induce corrosion. H2S formed during some reactions also causes corrosion in iron-based metallurgies by forming iron sulfide (FeS). The reduction of undissociated carbonic acid (H2CO3) in turbulent areas can also cause CO2 corrosion.  Rich amine can result in the pitting of the piping, exchangers, and the reboiler section, with higher temperatures and free gases acting as the culprits.

Amine systems must be designed to overcome these special problems. Amine treatment, or “gas sweetening,” has proved to be the primary method for gas/liquid purifications by removal of H2S and CO2. This means having a proven and reliable separation system is crucial for the H2S and CO2 removal as well as other gases to keep amine systems functional and mitigate corrosion and amine loss.