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Acidic and basic contaminants in amine treating

Sources of heat stable salt (HSS) contaminants in amine treating solutions are discussed and their effect on reaction equilibria in acid gas-amine systems is analysed.

Ralph H Weiland and Nathan A Hatcher
Optimized Gas Treating, Inc
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Article Summary
The requirement of solution electro-neutrality is used to validate solution analyses. Case studies demonstrate the important role of HSSs in determining amine plant performance, that simulations must incorporate ionic contaminants into their calculations, and the need to simulate the whole plant rather than isolated units.

A common and proven way to remove the acidic components CO2 and H2S from gas streams is by absorption into aqueous solutions containing one or more amines. Use of alkanolamines dates from the patent awarded to Bottoms in 1930. However, despite nearly 80 years of commercial use, further developments in amine treating continue to appear each year. Triethanolamine (TEA) was the first alkanolamine applied commercially but today it has been completely supplanted by a large number of other amines used singly or in mixtures with other amines, 
as well as with non-amine additives. Along 
with these changes, our ability to simulate and predict the performance of amine treating processes has increased enormously in recent years.

Commercial software packages for amine plant simulation use column models that range from simple equilibrium stages, equilibrium stages modified for reaction kinetics, equilibrium stages with computed stage efficiencies, right through to true mass and heat transfer rate models. However, regardless of the underlying principles on which each one is based, simulations of amine plants have traditionally assumed the solvent to be perfectly clean, meaning that it contains only water, amines, and acid gases. In some cases, the solubility of light hydrocarbons and inert gases may be taken into account. Until recently, however, the process effect of organic and inorganic acids that enter amine solutions when tail gas from Claus sulphur plants is treated, or which are almost universally encountered in oil refining operations, has been ignored. These components are called heat stable salts (HSS) or heat stable amine salts (HSAS). A few are acids, both organic and inorganic, that occur in treating solvents at a total concentration that does not typically exceed ten to fifteen thousand parts per million by weight, and is often very much lower than this. Apart from being blamed for corrosion problems, HSSs can have a profound effect on process performance. Ignoring them or misunderstanding their chemistry can lead to very bad processing decisions, to recommendations to make expensive equipment changes that, in fact, make the process worse than ever, and to continuing to surround a number of modern proprietary solvents with an undeserved mystique. Indeed, HSSs are sometimes purposely added to an amine solvent to boost the level of treating performance well beyond that attainable in a “clean” system. They can be both friend and foe — how to view them and deal with them in a given circumstance depends on understanding the chemistry, vapour liquid equilibrium constraints, and the mass transfer rate processes taking place in absorption and regeneration columns. Outside the laboratory, clean solvents exist in many plants for only a short time immediately following initial system charging and startup. In real processes, solutions are always contaminated to some degree. The work reported here attempts to provide a scientific understanding of HSS chemistry and the effect of these components on the process.

Heat Stable Salt Process Chemistry

Over time, solvents accumulate contaminants primarily from the gases being treated or through the use of makeup agents (water and amine) that are not completely pure. Contaminants of interest here are frequently the anions of organic and inorganic acids, also called heat stable salts (HSSs). Anions commonly found in amine solutions include thiosulphate, oxalate, sulphite, sulphate, glycolate, propionate, acetate, thiocyanate, formate, and chloride, which usually enter the solution as a result of absorption from the gases or liquids being treated. Contaminants may also be cationic such as alkali metal ions (sodium, potassium, calcium, and magnesium) that accumulate from makeup water hardness or through deliberate addition in the form of hydroxides or carbonates to deprotonate amine associated with HSAS anions. As contaminants, all of these ions can have a profound effect, sometimes positive, frequently negative, on amine treating unit performance. Other HSS anions such as sulphate or phosphate are purposely added to enhance H2S removal in tail gas treating units (TGTUs), a practice that, with greater understanding of the basic science, is becoming increasingly common.

Sources of Heat Stable Salts
There are three major sources of acidic and basic contaminants in most amine systems: cracking unit operations (refinery FCCs and Cokers for example), oxidation products from Claus sulphur plants, and certain amine reclaiming practices (see Hatcher et al., 2006).

After a period of use, especially in treating sour gases generated from refinery cracking operations (Cokers, FCCs), trace amounts of acid anion contaminants can build to significant levels in the solvent. The most commonly found acid anions are formate and thiocyanate, which result from the absorption of hydrogen cyanide. Formate is formed by the hydrolysis of the cyanide ion to ammonium formate, while thiocyanate forms from dissolved oxygen reacting with H2S, followed by reaction of the oxysulphur anion with cyanide ion. Higher molecular weight organic acid anions come from the hydrolysis of higher molecular weight nitrile compounds. Ammonium ion produced by the hydrolysis reaction will yield an H+ to the amine; the resulting ammonia molecule is then stripped from solution by steam in the regenerator and it accumulates in the overhead condensing system. This leaves the protonated amine/HSS anion pair in the amine solution. The reactions are:

RCN + 2 H2O →→ NH4+ + RCOO- (R=H, alkyl group) (1a)

NH4+ + R1R2R3N↔↔ R1R2R3NH+ + NH3 (1b)

2 HCN + O2 + 2 H2S + 2 R1R2R3N →→ 2 R1R2R3NH+ + 2 SCN- + 2 H2O (1c)

Hydrogen from gasoline reformers can also contain HCl which will react directly via acid-base neutralisation with the amine. Thus, for a strong acid HnX where X is an n-valent anion (Cl –, SO4=, etc.) the reaction with amine is

HnX + n R1R2R3N → n R1R2R3NH+ + X–n (2)   
Thiosulphates generally result from the reaction of dissolved oxygen with H2S or from SO2 reaction with H2S in Claus tail gas units when no HCN is present. Sulphates can either be formed from absorption of sulphuric acid or from further oxidation of thiosulphates. The reactions are

2 H2S + 2 O2 + 2 R1R2R3N →→ 2 R1R2R3NH+ + S2O3= + H2O (3a)

2 H2S + 4 SO2 + H2O + 6 R1R2R3N → 6 R1R2R3NH+ + 3 S2O3= (3b)

S2O3= + 5/2 O2→ 2 SO4=  (3c)
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