Amine Corrosion

The importance of Amine Unit is commonly underestimated, it is one of the most important units not only in refining operations but also Oil&Gas exploration and Petrochemical production. This chapter highlights some important aspects of corrosion caused by lean and rich amine solvents.

General Information

Removal of acidic compounds (H₂S, CO₂, COS etc.) from hydrocarbon streams, both liquid and gaseous, is a critical aspect of refinery operations. The purification of hydrocarbon streams from acidic compounds is commonly achieved through the absorption-desorption process, employing various alkanolamine-based solvents.

Figure 1 illustrates a typical amine unit configuration with a simple absorber/contactor – regenerator setup. However, variations of this arrangement are also possible, depending on factors such as treatment type, the solvent used, or the type/concentration of acid compounds.

Schematic diagram of typical amine unit.[1](#reference1) [2](#reference2) [3](#reference3)

Figure 1: Schematic diagram of typical amine unit.¹ ² ³

The following are four amine solvents predominantely used in sweetening units:

It’s important to mention that, in addition to standard solvents, there exists a diverse range of proprietary amine mixtures and physical solvents. These formulations are typically constructed using conventional solvents or their mixtures, incorporating proprietary additives or newly developed chemicals to achieve specific absorption/selectivity/stability properties of the final solvent. However, solvents of this specialized nature are beyond the scope of this chapter.

Each amine possesses specific properties for the selective absorption of CO₂, H₂S and other gas contaminants like COS or CS₂. In general, the overall process is based on a reversible reaction between the amine (base) and the respective acidic species, as illustrated in simplified Equation 1-4.

These and other reactions have implications for the corrosiveness of the amine solution. For example, increasing the amine concentration and CO₂ gas loading will inevitably lead to a higher concentration of HCO₃^-, which triggers the corrosion reaction, as illustrated in the example Equation 5.

Since the equilibrium of reversible reactions is dependent on temperature and concentrations of individual species (with pressure playing a negligible role in the given system), it is imperative to maintain specific process temperatures, amine concentrations, and acid gas loadings to minimize solvent corrosiveness. Table 1 provides examples of widely used solvents, along with their typical maximum loads for rich and lean streams.

Table 1 Popular solvents, typical concentration ranges, max loads and other information. ³ ⁴ ⁵ ⁶

Solvent	Type	Selectivity & properties	Conc., wt.%	Rich load, mol/mol	Lean load mol/mol	Reboiler T, °C
MEAⁱ	Primary	Not removing COS & CS₂	15-30	0.30-0.45	0.10-0.15	115
DEA	Secondary	Partly removing COS & CS₂	20-30	0.40-0.70	0.05-0.08	118
MDEA	Tertiary	H₂S selective	50-55	0.45-0.50	0.004-0.01	121
DGA®ⁱⁱ	Primary	Removing COS & CS₂	40-60	0.30-0.40	0.1	127

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References

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^{i- Parameters like max loading and concentration will depend on several factors like presence of H2S, inhibitors etc.}
^{ii - Aminoethoxy ethanol known by trade names DGA® or Diglycolamine® which are registered trademarks of Huntsman Corporation.}