Gas 2025 Issue

Corrosion mitigation of amine units using MEA for deep CO 2 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

I n Part 1, published in PTQ Q1 2025, various corrosion chal- lenges 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. H 2 S and CO 2 removal by amines Monoethanolamine (MEA) is a primary amine and the strongest amine when compared to secondary (DEA) or ter- tiary (MDEA) amines. MEA has substituted one single etha- nol group (CH 2 -CH 2 -OH), leaving two hydrogens attached to the nitrogen in the molecule (see Figure 1 ). All gas treating amines (primary, secondary, or tertiary) react instantane- ously with hydrogen sulphide (H 2 S), using their loan pair of electrons over the nitrogen. However, they all react differ- ently towards carbon dioxide (CO 2) . The CO 2 replaces the hydrogen attached to the nitrogen in MEA. Thus, the presence of hydrogen in the MEA chem- ical structure means that there are two active sites for CO 2 reaction. This makes MEA an attractive molecule for both H 2 S and deep (very low) CO 2 removal in key applications. Typically, CO 2 and H 2 S 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 appli- cations. 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.

common CO 2 removal process using an amine unit, such as at the gas plant in this article, CO 2 corrosion can occur in any zone where the CO 2 partial pressure is high, tem- peratures are elevated, or solvent velocities are high. Any combination of two to three of these factors often results in severe corrosion. Since the H 2 S partial pressure is very low, there will be minimal protective iron sulphide film on the walls of the unit, leaving the CO 2 to form pits that could pass right through the walls of the unit equipment. High CO 2 contents com- bined with warm/hot contactor temperatures generally cause CO 2 attack on the contactor walls (via carbonic acid attack caused by the CO 2 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 bot- tom 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 load- ing has, there are still significant issues in the regeneration of

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In this testing work, in order to get meas- urable corrosion rates, the testing was done at elevated tempera- tures in a continuous CO 2 atmosphere. In a

Loan pair of electrons

MEA molecular structure H CH CH OH H N

Solvent type

Figure 2 Relative corrosion tendencies of alkanolamines ( Depart, LRGCC 1991 ) Hot skin corrosion test, CO 2 atmos- phere, carbon steel, seven-day test @210°F (99°C)

Figure 1 MEA molecular structure

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