Controlling corrosion in amine treatment units
A range of measures can be taken to minimise corrosion in amine units. The amine unit plays a vital role in the petroleum refining, gas processing, coal gasification and ammonia manufacturing industries.
Jaya Rawat, Peddy V C Rao and N V Choudary
Bharat Petroleum Corporation
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With advances in hydroprocessing technologies to reduce sulphur levels in gasoline and diesel fuels, the requirement for an efficient, well-established and reliable separation system for the removal of gases such as H2S and CO2 has become an important requirement for refiners. Amine treatment has proved to be the principal commercially established method for gas/liquid purifications by removal of H2S and CO2.
In many cases, the removal of only H2S is required; CO2 remains in the system, where it can be managed by optimising the reaction rates of amines and treating gases. The treatment involves the removal of H2S and CO2 gases from flue gases and LPG, with the help of amines such as monoethanolamine (MEA), diethanolamine, (DEA) methyldiethanolamine (MDEA) and diisopropanolamine (DIPA), which have a tendency to absorb both the gases. In an absorber column, sour flue gas or LPG comes into contact with lean amine. The treated gas/LPG goes for end use and the H2S-rich amine then goes to the regenerator column.
During this process, major problems of corrosion and instability of operation raise a significant threat to an amine gas-treating plant, resulting in unscheduled breakdowns and outages. Major corrosion failures in these units have been attributed to free acid gas and high temperatures. Within this process, contaminant byproducts called heat stable salts (HSS) are formed and they gradually build up beyond tolerable limits in the amine circulation loop. Amine plant operational problems, such as excessive foaming, corrosion and capacity reduction, are often attributed to the accumulation of amine HSS. Significant amine loss has been observed in the operation of these units because of its high foaming characteristics.
Amine treatment process
The treatment involves the removal of H2S and CO2 from fuel gas and LPG with the help of amine solutions, which tend to absorb both gases. A process flow diagram of the unit is shown in Figure 1. In the absorber column, the sour fuel gas or LPG comes into contact with lean amine, which absorbs H2S and CO2. The treated gas/LPG goes for end use and the H2S- and CO2-rich amine then goes to the regenerator column. In the regenerator column, the rich amine solution is stripped of its absorbed sour gases, with steam as the heating medium, so that the regenerated amine can be reused in the absorber.
The steam strips out the absorbed H2S and CO2 present in the amine solutions according to the following reactions:
R2NH3S → R2NH + H2S (1)
(R2NH3) CO3 → R2NH + CO2 + H2O (2)
where R is a CH2CH2OH group.
The liberated acid gases and steam from the top are cooled in the overhead condensers. The uncondensed gas goes to the sulphur recovery unit via a pressure control valve and condensed liquid is pumped back to the column as a total reflux. From the regenerator bottom, lean amine exchanges heat with feed-rich amine before entering the absorbers.
The absorption process is used to remove a component (solute) from the gas stream by contacting the gas with a liquid solution (see Figure 2 and Equation 3):
The amine solvent is the water solution of an alkanolamine used to remove the H2S, mercaptans and CO2. The most common amines used include MEA, DEA, DIPA, MDEA and diglycolamine (DGA). These amines are very water soluble because they contain hydroxyl groups. The nitrogen or ammonia group (NH3) reacts with the acid gas to form a water-soluble salt. Typical properties of the amines and their structures are given in Table 1.
Some of the important criteria for the selection of amines are:
• High solubility
• Low volatility and viscosity
• Easy recovery
• Least corrosive and least cost.
Corrosion problems in amine units
Corrosion in the amine system is mainly caused by acid gases, strong acids, contamination such as amine HSS and amine degradation products. H2S formed during some reactions also causes corrosion in iron-based metallurgies by forming iron sulphide (FeS). CO2 corrosion is caused by the reduction of undissociated carbonic acid in turbulent areas, where a passive ferrous carbonate scale is unable to form. Carbonic acid can undergo the following reactions:
H2CO3 + e- → HCO3- +H (4)
H2CO3 → CO2 + H2O (CO2 gas evolution) (5)
The organic acids and many amine degraded products, high velocities and turbulence break down an FeS protective layer and remove iron from the metal. The corrosion product is water stable until it contacts the high H2S concentrations in the absorber. FeS is formed and precipitates to create deposits, while acid is returned to resume the corrosion cycle.
Corrosion in the overhead systems is caused by an accumulation of high concentrations of H2S, nitrogen compounds and CO2 along with a variety of acids. Rich amine causes pitting of the exchangers and piping, as well as the reboiler section, where free acid gases and higher temperatures are the main driving forces of corrosion
Formation of heat stable amine salts
Heat stable amine salts (HSAS) are formed by the reaction of inorganic contamination of the amine solution with strong and weak acids. Acids increase the corrosion, fouling and emulsification potential and reduce the gas-treating capacity.
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