Apr-2025

Corrosion mitigation of amine units using MEA for deep CO2 removal: Part 2

Amines used in gas treating affect reboiler and regenerator stainless and carbon steel components, influenced by temperatures, chlorides, acid gas loadings, and other factors.

David B Engel, Scott Williams and Cody Ridge
Nexo Solutions

Article Summary

In Part 1, published in PTQ Q1 2025, various corrosion challenges faced by amine units using MEA solvent during their operation were discussed, along with basic information related to the background of amine solvents and corrosion events. In Part 2, the content is developed in greater depth in terms of the chemical aspects and their process implications.

H2S and CO2 removal by amines
Monoethanolamine (MEA) is a primary amine and the strongest amine when compared to secondary (DEA) or tertiary (MDEA) amines. MEA has substituted one single ethanol group (CH2-CH2-OH), leaving two hydrogens attached to the nitrogen in the molecule (see Figure 1). All gas treating amines (primary, secondary, or tertiary) react instantaneously with hydrogen sulphide (H2S), using their loan pair of electrons over the nitrogen. However, they all react differently towards carbon dioxide (CO2).

The CO2 replaces the hydrogen attached to the nitrogen in MEA. Thus, the presence of hydrogen in the MEA chemical structure means that there are two active sites for CO2 reaction. This makes MEA an attractive molecule for both H2S and deep (very low) CO2 removal in key applications. Typically, CO2 and H2S can be removed to values less than 5 ppmV. The loan pair of electrons over the nitrogen in MEA is very active for reactions, especially with steel and corrosion, which limits solvent strength.

Amine solvents, in general, have low corrosivity and have historically been used as corrosion inhibitors in multiple applications. Nevertheless, when amines are subjected to acid gas loading, the allowable strength must be limited based on how aggressively the amines and their salts attack the metal surface. Testing work presented at a gas conference in 1991 showed the relative corrosion tendencies of the three types of alkanolamines in relation to their concentrations (see Figure 2). Typical acceptable corrosion rates for amine units are <5 mils/yr.

In this testing work, in order to get measurable corrosion rates, the testing was done at elevated temperatures in a continuous CO2 atmosphere. In a common CO2 removal process using an amine unit, such as at the gas plant in this article, CO2 corrosion can occur in any zone where the CO2 partial pressure is high, temperatures are elevated, or solvent velocities are high. Any combination of two to three of these factors often results in severe corrosion.

Since the H2S partial pressure is very low, there will be minimal protective iron sulphide film on the walls of the unit, leaving the CO2 to form pits that could pass right through the walls of the unit equipment. High CO2 contents combined with warm/hot contactor temperatures generally cause CO2 attack on the contactor walls (via carbonic acid attack caused by the CO2 dissolving in the condensed water on the vessel walls), which manifests as pitting corrosion at the hot zones in the contactor tower.

Corrosion in amine units using MEA solvents is primarily focused where the contactor tower maximum temperature occurs (bulge), which often times is near the middle section of the contactor given the low absorption rates at the bottom of the column. The predicted temperature profile in the contactor, as presented in Figure 3, shows the temperature bulge in the mid-section of the column.

Amine regeneration and corrosivity
Even though the lean amine loading has not dramatically exceeded the recommended values, as the rich amine loading has, there are still significant issues in the regeneration of the amine that will cause corrosion of both carbon steel and stainless steel. Regeneration of the amine solvent is achieved by counter-currently reacting the solvent with steam flowing up the regenerator tower.

MEA is a very strong primary amine, so it does not want to give up its reacted acid gas easily. It takes significant steam energy to regenerate rich MEA. One can tell that the unit has generated sufficient steam to properly regenerate the rich amine solvent by checking the regenerator overhead temperature. For MEA solvents, this temperature must be 225-235°F (107-113ºC). The actual value was only 192°F  (89ºC).

Hence, regeneration was not taking place properly. The low temperature out the top of the regenerator is a result of the loss of steam at the top of the column section. The steam generated in the reboiler has three objectives:
υ Heat the feed solvent to the reboiler temperature (sensible heat load).
ϖ Break the reaction bond between the CO2/H2S and the MEA.
ω Provide enough energy for a reflux flow between 7-10% of the main circulation flow rate.

For the regenerator heat load, the energy required to heat the solvent is increased when the feed temperature is cooler than the recommended 195°F minimum. According to plant data, the rich amine feed temperature was only 160°F (71ºC), which means the steam has to heat up the solvent by 90°F instead of 45-55°F in a typical amine unit. The extra steam wasted in heating up the solvent reduces the amount of steam available to regenerate the CO2 and H2S from the rich amine solvent.

This means the regenerator runs out of steam before steam reaches the top of the regenerator, so rather than stripping acid gases out in the top of the regenerator (ideal situation), rich amine travels deeper down the regenerator and even into the reboiler before the amine is finally regenerated. This is one of the most common causes of regenerator corrosion.

H2S is a slightly weaker acid gas than CO2 (carbonic acid), so it is more easily regenerated higher up the regenerator. Excessive CO2 in the hottest part of the regenerator and reboiler leads to excessive corrosion all the way through the hot lean piping until the amine solvent is cooled in the lean/rich (L/R) exchanger. As the simulation graphs show (see Figure 4), CO2 is still being regenerated in the bottom of the regenerator, whereas most H2S is removed by the time the amine solvent flows into the reboiler. This is a situation with a very high corrosion potential.

Regenerator and reboiler corrosion
To mitigate corrosion in the regenerator, regeneration of 95% of the rich amine must happen before entering the reboiler. A second rule is to reduce reboiler and vapour return line corrosion to maintain the CO2 content of the reboiler return below 1 mol%.