Amine Corrosion

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.

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}

Mechanism

Pure alkanolamine solutions are normally considered as non- or low corrosive to carbon steel. Absorption of acidic components will increase solvent corrosiveness in the way shown on below reactions (A). The presence of contaminants like O₂, CO or SO₂ is another factor that will impact on amine’s corrosivity. These contaminants will cause amine degradation as shown in a few example reactions below (B).

Organic acids formed in this process will react with amine (base) and will form respective salts. These salts cannot be decomposed to amine and acid in typical regeneration process (hence, are called typically Heat Stable Amine Salts – HSAS) and will cumulate in solvent causing increase of its corrosivity. Each solvent exhibits a distinct decomposition pattern, leading to varying setups and concentrations of HSAS.

A: Reactions with CO lead to stable amine carbamate.

B: Oxidation, which continues (based on oxygen supply) from formation of amino acid (glycine), up to oxalic acid. Oxalic acid at elevated temperature (>120°C) will decompose to formic acid.

Above reactions represent only a small portion of potential degradation paths present in various solvents and with different contaminants. The concentration of Heat Stable Amine Salts (HSAS) is one of key-controlling factors that helps mitigate amine corrosion.

Key variables

Amine corrosion, like many other damage mechanisms, is affected by operating parameters such as temperature and flow (velocity/WSS). Additionally, the corrosiveness of alkanolamines is governed by the solvent type, its concentration, and the concentration of contaminants (which are also influenced by the type of contaminants) or acid gas load.

Amine type and concentration

As highlighted earlier, pure alkanolamines are not particularly corrosive, and their aggressiveness results from absorbed gases such as CO₂ and/or H₂S. Primary amines (like MEA) are generally considered to be more aggressive than secondary (DEA) and tertiary (MDEA). These expectations are overly simplified because the final corrosiveness of a given solvent will be a superposition of amine type, concentration, and specific setup of other variables (acid loading, temperature etc.). Figure 2 shows a change of MEA corrosivity under increasing amine concentration.

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Temperature and acid gas loading

Chemical reactions typically adhere to the general temperature-reaction rate relations described by the Arrhenius equation. Corrosion reactions in alkanolamine solutions are no exception and follow the same principle. Since the absorption process is exothermic, the temperature inside the contactor/absorber will locally increase, leading to the formation of hot spots (>90°C / >194°F) conducive to corrosion activities (refer to Figure 3). The rich amine stream exiting the absorber typically maintains a temperature range of 70-80°C (158-176°F), thus exhibiting relatively lower corrosiveness up to the flash-tank. However, this condition may vary with the increase in amine strength and acid load, as demonstrated in Figure 4. For typical acid gas load values concerning common solvents, please consult Table 1.

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Flow

Flow-accelerated corrosion can occur even in seemingly ’non-corrosive’ solvent streams, where parameters such as acid load, HSAS, or temperature are within ‘safe’ boundaries. This issue is often overlooked by designers who may be misled by various ‘industry-accepted’ rules of thumb, sometimes endorsed by standards like API RP 571, API RP 581, or API RP 945. Additionally, operators managing specific amine unit configurations may lack full control over flow in certain segments of the unit. Table 2 provides some typical velocity limits for popular solvents.

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Expectedly, there is no clear consensus on amine velocity limits; however, most authors seem to accept the range of 1.5-1.8 m/s (5-6 ft/s) for the rich stream. The boundary for lean amine flow velocity is even less clear. It appears that 6 m/s (20 ft/s) for lean solvent is too high, and a more reliable or conservative level would be in the same range as for rich amine (1.5-1.8 m/s).

It is important to emphasize that maintaining low velocity does not always equate to minimizing flow-accelerated corrosion. Flow restrictors such as tees, elbows, or weld protrusions may locally generate flow turbulence, ultimately leading to elevated corrosion. Therefore, it is crucial for designers and plant engineers to consider not only flow velocity but also Wall Shear Stress (WSS) as a parameter that can accurately assess adequate flow boundaries.

Generally, within normal operating flow and with a single liquid phase system, WSS does not change dramatically (e.g., from 50Pa to 100Pa). However, this increase can potentially raise the corrosion rate by 10-20%, which might be sufficient to damage specific pipe areas before the planned inspection interval (refer to Figure 5).

In two-phase flow scenarios, such as in the reboiler and reboiler-to-stripper loop, the situation becomes even more dynamic. Here, the effects of flow and values of WSS can become locally very high, potentially impacting even corrosion-resistant alloys. This, coupled with overlapping actions from evaporation, HSAS deposits, etc., may ultimately lead to elevated corrosion.

Contaminants/Heat Stable Amine Salts (HSAS)

The presence of contaminants such as oxygen, CO, or COS, as well as temperature-driven amine decomposition processes that occur independently of the contaminants, slowly deteriorates the solvent properties. The basic mechanism of HSAS formation is relatively simple: strong organic acid anions formed during decomposition (refer to Mechanism) replace weaker acid anions HS^- and HCO₃^- in the respective amine-acid gas reactions. Because organic acids cannot effectively leave the amine solution during the regeneration process (e.g., CO₂ and H₂S readily evolve from the solvent), the concentration of amine molecules bonded with strong acids will increase over time, reducing amine absorption capacity.

Additionally, lighter acids such as formic and acetic may evolve inside the reboiler due to temperature, accelerating corrosion not only of carbon steel but also of popular austenitic steels (304L/316L). Other compounds formed from the decomposition of amine solvents, such as thiosulfates, amine-acids like bicine or glycine, and complex decomposition products like N-(2-hydroxyethyl)-ethylenediamine (HEED) and N,N’bis(hydroxyethoxyethyl) urea (BHEEU), will also affect the solvent’s corrosiveness.

There are several methods to reduce HSAS, including traditional thermal reclaiming (low pressure), vacuum distillation, ion-exchange, electrodialysis, etc. However, the most popular technique for reducing HSAS in solvent circulation remains side-stream (typically 0.5-5% of the total volume) thermal reclaiming, which is successfully used in MEA and DGA units, for example.⁵ Specific details of reclaiming technology are beyond the scope of this document.

The more critical factor is related to the overall concentration of HSAS and its control during normal amine unit operation. It is important to highlight that the generic guidelines on HSAS concentration levels published in API documents (API RP 571, API RP 581, or API RP 945) should be treated carefully. Another element, sometimes overlooked by engineers, is the expression of HSAS concentration – whether with respect to the total mass of solvent or with respect to amine alkalinity. It should always be clearly stated whether a given HSAS concentration is referred to as amine or total solvent, for example, “2 wt% HSAS as amine.” Otherwise, there will be confusion regarding maintaining the adequate HSAS level. For instance, with a 50% amine concentration and HSAS of 2.5 wt% as amine, the HSAS concentration in the solvent would be approximately 5 wt%. Table 3 provides examples of HSAS levels for different solvents.

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The total HSAS concentration serves as a general guideline for establishing control boundaries. However, for specific amines, it is imperative to also have detailed rules for individual HSAS ions, such as formates, thiocyanates, or thiosulfates, as well as the concentration of amino acids and complex decomposition products. These elements, whether considered individually or jointly, may significantly increase the solvent’s corrosivity. Table 4 provides examples of concentration levels for major HSAS ions and other compounds that may influence the solvent’s corrosiveness.

Except for commonly accepted limits for thiosulfates, thiocyanates, and formates (1 wt.%), as well as acetates and chlorides (1000 ppm), limits for other contaminants are not always clear. These limits sometimes vary between 0 and 1000 ppm, depending on the specific amine and acid gas load. Similarly, limits for amino acids (such as bicine) or amine condensation products (like diamines such as THEED) are also not clearly established and may range from 2000 ppm to less than 250 ppm, or for THEED (DEA) less than a 1.5 wt.% solution.^{18 24} These observations confirm the hypothesis that “safe corrosion” concentration levels for individual contaminants should be used with caution, and their impact should be analyzed individually based on the amine type, acid gas loading, or overall operating conditions.

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Materials

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Tools

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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.}