Feb-2025

Corrosion mitigation of amine units using MEA for deep CO2 removal: Part 1

Case study describing a gas plant experiencing high corrosion rates in the unit’s major equipment, including the regenerator and contactor towers.

David B Engel, Scott Williams and Cody Ridge
Nexo Solutions

Article Summary

Amine units are under constant corrosion conditions and must be closely monitored. A gas plant experiencing high corrosion rates and increased corrosion rates used monoethanolamine (MEA) as a solvent to remove H₂S and CO₂. Corrosion rates appeared to increase over time as major equipment and probes were periodically replaced. Corrosion was found in many areas of the unit, including the regenerator and contactor towers. The lean/rich heat exchanger and stainless steel probes also presented accelerated corrosion rates.

The inlet gas flow rate ranged from 10-13 MMSCFD (75 psi), with only about 10-11 MMSCFD treated in the amine unit. The amine solvent flow rate varied from 45-55 GPM. MEA often produces increased corrosion rates due to the higher regeneration energy and the inherent increased corrosivity of MEA and MEA salts in the solvent. The feed gas H₂S composition has decreased in the last couple of years, while the CO₂ concentration ranged from 1-1.5 mol%.

Table 1 shows the analytical history of the solvent. The data indicated elevated chromium levels consistent with stainless steel corrosion and elevated iron levels consistent with carbon steel corrosion. High acid gas loadings in the solvent samples were contributing factors to the increased corrosion rates. The solvent loadings (lean and rich) were higher than the maximum recommended values. For CO₂-only service, the maximum rich loading for MEA is 0.35 mol/mol (without using corrosion inhibitors). Due to low H₂S concentrations, it is recommended that the rich loading be below 0.35 mol/mol. 

Pictures of the amine unit were taken with a thermal camera. While interesting findings were made, facility insulation hindered evaluation. Figure 1 shows the lean/rich heat unit exchanger using a reference temperature range. The eight-tube pass heat exchanger had a two-shell pass for the lean solvent side of the exchanger. Normally, the lean solvent should gradually decrease in temperature until it exits the exchanger. However, it can be observed (Figure 1) that the lean amine solvent appears to flow downwards to the bottom of the exchanger prematurely, limiting heat exchange area and efficiency.

This can explain why the rich solvent outlet temperature of the exchanger was found to be 160°F when the minimum temperature should be 195°F. This would suggest that the seal strips on the lean solvent side of the exchanger were corroded, causing a bypass.

MEA is a primary amine and the strongest amine when compared to secondary (diethanolamine, DEA) or tertiary (methyldiethanolamine, MDEA) amines. MEA has substituted one single ethanol group (CH₂-CH₂-OH), leaving two hydrogens attached to the nitrogen in the molecule (see Figure 2). All gas-treating amines (primary, secondary, or tertiary) react instantaneously with H₂S using their loan pair of electrons over the nitrogen. However, they all react differently towards CO₂.

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

In a secondary alkanolamine, such as DEA (see Figure 3), the presence of the second ethanol molecule pulls the electron cloud away from the nitrogen, thus reducing its  reactivity with steel.

In the tertiary amine MDEA (see Figure 4) compared to DEA, the replacement of the third hydrogen with a methyl group hinders the acid-base reaction by steric hindrance,  thus reducing reactivity and the overall intrinsic corrosion tendency of the molecule. The result is the ability to operate MDEA at a strength of 50-55 wt%. Testing work presented at a previous gas conference showed the relative corrosion tendencies of the three types of alkanolamines in relation to their concentrations (see Figure 5). Typical acceptable corrosion rates for amine units are <5 mils/yr.

To get measurable corrosion rates in the study related to Figure 5, the testing was done at elevated temperatures in a continuous CO₂ atmosphere. In a primarily CO₂ service amine unit, such as at the gas plant from this case, 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 will result in very severe corrosion events.

Amine solvents, in general, have low corrosivity. Amines have also historically been used as corrosion inhibitors in multiple processes. Nevertheless, when amines are subjected to acid gas loading, the allowable strength must be limited based on how aggressively the amine and their salts attack the metal surface. Laboratory data, in conjunction with plant data, indicate that as amine strength and loadings are increased, corrosivity is enhanced. For this reason, MEA facilities should limit their amine strength to a maximum of 20 wt%, their lean loading to a maximum of 0.15 mol/mol, and their rich loading to a maximum of 0.35 mol/mol. If there is H₂S present in the feed gas at a concentration sufficient to form iron sulphide films in the amine unit, then the rich loading could potentially reach 0.40 mol/mol.

The plant has been operating below the maximum MEA strength guideline of 20 wt%. In fact, the trend line for the strength has been dropping over the tested time frame. Regarding amine loading, both the lean and rich loadings have been at the upper end of the recommended range, and for the rich loading, in particular, the values have exceeded recognised corrosion minimisation guidelines.

As the trend line in Figure 6 shows, the rich loading (red) has been trending upward. This is as expected since the amine strength has been trending downwards. Since amine loading is described as moles of acid gas divided by moles of amine, a decline in amine strength will naturally result in an increase in loading. This is assuming the feed gas rates and compositions are consistent over time.

As the H₂S level in the feed gas has declined over time, the ratio of CO₂ to H₂S in the rich solution has increased. This is significant for several reasons, including the inability to lay down and maintain a protective iron sulphide passivation film and the inability to build a comparable iron carbonate protective film. Note that iron carbonate passivation layers are less protective, more porous, and have a lower mechanical strength.