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There is already a significant amount of information in the literature on

corrosion in amine units. The following is an overview of the issues involved.

2.1 Process issues

2.1.1 Pretreatment

Units often use a knock-out pot before the absorber where liquid hydrocarbonand water are removed.

2.1.2 Absorber

In the absorber, the amine removes H2S, CO2 and mercaptans by forming

a salt. MEA, DEA, MDEA, DIPA and diglycolamine (DGA) are the

main amines that are used. Lean amine flows down the absorber in

counterflow to the fluid that is being treated, which exits at the top withthe impurities substantially removed. The amine that has absorbed the

impurities is then referred to as rich amine and exits from the bottom of the

absorber and flows to a regenerator. Several absorbers may feed a common

regenerator.

The amine will also remove stronger acids in the absorber such as formic

acid (amongst others) and the reaction with these acids is difficult to reverse,

causing a build-up of heat-stable amine salts (HSAS) in the amine.

2.1.3 Regenerator

Rich amine goes to the lean–rich exchanger and then on to the regenerator.

Rich amine passes on the tube side to avoid pressure changes and flashing.

In the regenerator, acid gases are stripped by reduction in pressure and

increase in temperature. Heat is provided by a reboiler, the temperature of

which needs to be carefully controlled in order to reduce degradation of the

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Amine unit corrosion in refineries4

amine. The amine salt liberates the acid gas, which exits to the overhead, and

lean amine, which exits from the bottom and is filtered.

2.2 Important issues

Important issues to be considered are:

• Amine type and strength.

• Acid gas loading.

• Temperature.

• HSAS.

• Solids and filtration.

• Wet H2S cracking.

• Amine cracking.

• Species found in regenerator overheads.

2.3 Corrosion issues

2.3.1 General factors

The amine itself is not corrosive, but corrosion is promoted by the following:

• Entrained acid gases.

• Higher concentration of corrosive species.

• Higher temperatures.

• Corrosion on heat transfer surfaces.

• Higher velocities.

• HSAS.

2.3.2 Mechanisms

Wet H 2S corrosion

Fe + H2S = FeS + H2

FeS is more protective than FeCO3.

Wet CO2 corrosion

Fe + H2CO3 = FeCO3 + H2

Wet CO2 corrosion can result in high corrosion rates, but a carbonate film

gives some protection and is more protective at higher temperatures. The

CO2 content is often not very high in refinery streams, except in hydrogen

reformer plant systems.

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Technical background 5

2.3.3 Rich amine

Corrosion in rich amine solutions is increased by high acid gas loading, and

the loading often has to be limited to minimise corrosion. Acid gas flashing

disturbs the FeS protective films. Acid gases break out of solution to give

acid attack when there is a high velocity and high temperature and when the

pressure is too low to suppress vaporisation.

2.3.4 Lean amine

It is important to avoid too low a level of H2S in the lean amine, as a small

amount of H2S is helpful in producing a protective sulphide film. Primary

amines are more corrosive than secondary and tertiary amines.

2.3.5 Acid gas attack

H2S forms protective sulphide films on carbon steel in many areas but there

are problems in areas where films can be removed. In such locations, upgrading

of materials is required, often to an austenitic stainless steel belonging to the

300 series.

2.3.6 Heat-stable amine salts

Heat-stable amine salts (HSAS) form from stronger acids than H2S and CO2

and they do not thermally break down at regeneration temperatures. Problems

arise from formic, oxalic, acetic and thiosulphurous acids and from chlorides,

sulphates, thiosulphates and thiocyanates which can come in from the feed

system. Oxygen is also a source of problems and this can come in from thefeed, amine storage and make-up water. Blanketing tanks with N2 and

maintaining a tight system are helpful in order to exclude oxygen.

High temperatures are also a problem and temperatures should be minimised

through control of the reboiler temperature.

HSAS can also be produced from CO and HCN. Therefore, some operators

treat gas from fluid catalytic cracking units (FCCUs) with polysulphide to

remove HCN.

The presence of HSAS reduces acid gas removal capacity, lowers pH,increases conductivity and dissolves protective films; so HSAS should be

minimised as much as possible.

2.3.7 Make-up water quality

Make-up water should ideally have low total dissolved solids and low total

hardness owing to calcium, low chlorides, sodium, potassium and dissolved

iron and should exclude oxygen.

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2.3.8 Erosion corrosion

Erosion corrosion is caused by dirty amine solutions containing solid

particulates; therefore lean amine is filtered to minimise solids.

Protective FeS films can be damaged and removed under conditions of

high velocity, turbulence or impingement. Benefit can therefore, be obtained

by designing to minimise impingement and turbulence, e.g. by using large

radius bends. The velocity in piping is usually kept below 1 m s–1, and 300

series stainless steel is required at pressure let-down valves.

2.3.9 Proprietary chemical additions

Some operators utilise proprietary chemical additions from their site chemical

supplier, although many prefer not to use these.

2.3.10 Corrosion in regenerator overheads

Corrosion in the overheads of the regenerator takes a different form from

that occurring elsewhere in the amine unit. H2S, NH3 and HCN are important

species that are involved, which can give corrosion. Conditions are more

aggressive when treating streams from cokers, visbreakers, FCCUs and

hydroprocessors.

NH4HS can be particularly aggressive, and close attention needs to be

paid to concentration and velocity with this species.

HCN is detrimental as it removes sulphide scales, which increases corrosion

and promotes hydrogen pick-up and damage:

FeS + 6CN = Fe(CN) + S–64– 2–

Special attention is needed in order to avoid excessive accumulation of NH4HS

and HCN in the regenerator overhead reflux system.

2.3.11 Hydrogen-related cracking in wet H2S systems

Sulphide stress cracking is prevented by minimising the hardness and strength

of the alloys used for wet H2S systems. This is accomplished through material

selection, and the control of weld procedures and post-weld heat treatment(PWHT).

Hydrogen-(pressure-)induced cracking (HIC), including stress-orientated

hydrogen-induced cracking (SOHIC), is mitigated by the use of improved-

quality steel plate and PWHT or the use of corrosion-resistant alloy cladding.

2.3.12 Alkaline stress corrosion cracking

API 945 recommends PWHT as follows:

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• MEA: PWHT for service at all temperatures.

• DIPA: PWHT for all temperatures.

• DEA: PWHT for temperatures of 60 °C (140 °F) and above.

•MDEA: PWHT for service at temperatures of 82

°C (180

°F) and above.

It is also necessary to take care of steam-out conditions.

2.4 Materials

Carbon steel can be used with success for many areas but material upgrading

is necessary in highly corrosive areas. Use has been made of materials such

as the austenitic stainless steels 304L and 316L, 2205 duplex stainless steel

and other high-alloy materials such as Alloy C or Stellite for valve trim.

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