Monoethanolamine amine solvent

Alkanolamines. Gas sweetening, ie, removal of hydrogen sulfide and carbon dioxide, using alkanolamines was patented in 1930. Several amine solvents are available as of the mid-1990s. The most widely used are monoethanolamine [141-43-5], diethanolamine [111-42-2], diglycolamine [929-06-6], and methyldiethanolamine [105-59-9]. Amine processes are generally applicable when hydrogen sulfide concentration in the feed gas is relatively low (eg,... 

Since that time, a general correlation between yield of extract and carbon content has been reported for ethylenediamine (Table 10.2). Various other amine solvents (e.g., monoethanolamine) show similar behavior insofar as the extract yield may decrease markedly with increase in rank for coals under 85% carbon. On the other hand, the yield of extract using solvents such as benzylamine, piperidine, and pyridine may show much less variation with rank, and the effectiveness of many solvents may decrease markedly for coal having more than 88% carbon (van Krevelen, 1965). 

Amine solvents are widely used for sour gas removal, in syngas, fertilizer and natural gas plants. They are mainly used to withdraw the sour components CO2 and H2S from process gas streams, and the process is usually carried out in packed-bed columns. Depending on the specifics of a particular process, either aqueous primary (e.g., monoethanolamine, MEA), secondary (e.g., diethanolamine, DEA), tertiary (e.g., methyldiethanolamine, MDEA) amines or aqueous amine blends are employed. 

The most widely used amine is monoethanolamine (MEA), which is considered as a benchmark solvent because of its high cyclic capacity, significant absorption-stripping kinetic rates at low C02 concentration and high solubility in water. Some other amine-based solvents such as diethanolamine (DEA), triethanolamine (TEA), diglycolamine (DGA), N-methyldiethanol-amine (MDEA), piperazine (PZ), 2-amino-2-methyl-l-propanol (AMP) and N-(2-aminoeth-yl)piperazine (AEP) have also traditionally been utilised. 

Chemical absorption, which involves a reversible reaction, forms weak chemical bonds between the solvent and the species to be removed. All processes using amines, such as monoethanolamine or methyldiethanolamine, and alkaline salt solutions belong to this category. 

Amine-based solvents have been enhanced over the years [2], such that primary (Monoethanolamine (MEA) Diglycolamine (DGA)), secondary (Diethanolamine (DEA) Diisopropanolamine (DIPA)) and tertiary (Methyldiethanolamine (MDEA) Triethanolamine (TEA)) variants are available through different suppliers, many of which include special proprietary additives to improve performance and other characteristics. The choice of a particular alkanolamine is primarily dictated by the requirements of the specific application. With the exception of a few, these amines have a maximum sorption capacity of 1 mole of CO2 to two moles of amines. Liquid tertiary amines and amidines have shown a higher sorption capacity with a ratio of 1 1 molar [3], thereby reducing the volume of amine, but the reaction rate is much slower. Amine blends have been used to compensate for this difference in order to reduce regeneration and recirculation costs and increase CO2 loading capacity. 

This concludes the major units in a refinery. There is one major auxiliary unit in a refinery that requires cleaning. This is the amine unit While there are many processes to remove HjS and/or CO2 from gas streams, the most widely used are the amine systems that depend on the reactivity of H2S with amino nitrogen for their absorption properties. The most currently used processes today are monoethanolamine (MEA), diethanolamine (DEA), diglycolamine (DGA), and diisopropylamine (DIPA). Deposits/solvent related to units described above that are not to be considered in more detail are given in Table 1. 

One of the most widely used commercial absorption processes is the removal of CO2 or HgS from a gas stream by contacting it with a solution of monoethanolamine or diethanolamine. Both of these solutions are alkaline and combine chemically with 14 mol of acid gas per mol of amine. Although a chemical combination exists, still even at equilibrium, the acid gas exhibits a vapor pressure above the solution. Because this vapor pressure of the absorbed acid gas increases rapidly with temperature increase, it is possible to regenerate the rich amine solution by stripping the heated solvent. 

---