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We didn’t expect severe corrosion issues in the carbon steel of our amine unit. What is causing it?

Jun-2021

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Sjaak van Veelen, MPR Services, Svveelen@mprservices.com

Some more information will be needed to give you a meaningful answer and to help you to solve the issues. It would be good to know where in the amine system you find the corrosion. What type of corrosion you see (e.g. pits, pools, cracks, blisters etc). What the operating parameters are like temperatures, acid gas loadings and if you have it: a recent amine analysis report.

Jul-2021
rajkumar chate, sulzer chemtech Ltd, rajkumar.chate@sulzer.com

Corrosion in the amine unit is very common. Most common reason for the corrosion is higher amine loading. Check the rich loadings. If it is >0.45 mol acid gas/mol amine then increase the circulation rate. This requires more energy for regeneration but if you are not limited by the lean end pinch then you can allow higher lean loading in lean amine.

Jul-2021
Gerrit Buchheim, Becht, Gbuchheim@becht.com

Severe corrosion in amine units is not rare and should be expected. Depending on where in the unit (absorber, hot rich exchangers/piping, regenerator bottom, regenerator top, or in the hot lean amine) corrosion is occurring will have different root causes. Typical culprits are excessive amine loading of H2S or CO2 or high velocities in the rich amine system, particularly in the hottest sections. Regenerator bottoms and hot lean amine piping and the reboiler return piping can be quite corrosive due to a lack of FeS protective scale, in hot lean amine systems, high heat stable salt loading and specific salts can be very corrosive. High velocity in the lean amine system aggravates corrosion rates. The regenerator overhead can be corrosive due to acid gases (H2S) and can be very corrosive if NH3 builds up if there is no purge on the regenerator acid gas outlet overhead drum reflux stream, to prevent ammonium bisulphide corrosion. Many units have upgraded austenitic stainless steel in the hottest rich and lean amine parts of the unit because of excessive corrosion. Beyond corrosion, PWHT is important to minimise amine SCC in lean amine and wet H2S SOHIC cracking in rich amine.

Jun-2021
Celso Pajaro, Sulzer Chemtech, Celso.Pajaro@sulzer.com

We will provide several potential explanations to the corrosion phenomenon:
Amine appearance: one indication of corrosion is the increased presence of solids in the amine solution. Allowing a high solid content in the amine accelerates erosion — corrosion problems as well as will increase fouling problems. The refiner will need to operate the filters at the maximum flow rate.
Check filters: take samples of the amine solution upstream and downstream of the filter to verify it is properly working, some filters have had problems with poor sealing that allows unfiltered amine to bypass the filtration element.
Check the amine appearance of the rich and lean amine, if the rich amine is dirtier (darker) than the lean amine please check the amine quality for:
    -    High CO2 content in lean amine (for units treating streams with H2S and CO2) will keep iron carbonate in solution, and once it enters the amine absorber it will precipitate iron sulphide. Increasing amine regenerator reboiler duty should reduce CO2 in the lean amine
    -    Another mechanism is the presence of amine degradation compounds that keeps iron soluble until it gets in contact with H2S in the absorber. There are several public guidelines on the maximum amount of amine degradation products for each type of amine.
    -    o    Excessive acid gas loading in the rich amine. High acid gas loading produces amine bisulphide that can penetrate the iron sulphide protective layer on the carbon steel and accelerate corrosion.
    -    o    High pipe velocities will produce an erosion-corrosion effect, amine solution velocity in carbon steel piping should be kept 6 ft/s maximum.
    -    o    Two phase flow can also accelerate corrosion in carbon steel piping.
    Rich amine pipe located downstream of the rich/lean amine heat exchanger should be checked for two phase flow, the rich amine control valve that feeds the regenerator should be as closed as possible to the regenerator inlet.
-        Rich amine pipe located downstream of the amine contactors control valve should also be checked for two phase flow, it is preferred to have the control valves as closed as possible of the amine flash drum.
    -    Equipment showing signs of corrosion due to wall thickness measurements or visual inspection
    -    o    Amine regenerator acid gas overhead drum. The presence of ammonium bisulphide or cyanides can penetrate the iron sulphide layer and attack the steel. An analysis of the reflux will help to determine if there are high concentrations of either component. If this is a problem, a portion of the reflux should be diverted to a sour water stripper unit.
    -    o    Amine regenerator reboiler. Poor amine regeneration can increase the acid gas content in the amine going to the reboiler. Once amine reaches the reboiler it will be heated allowing the release of the acid gas which will produce corrosion. Taking a sample of the amine before going to the reboiler will indicate if more regeneration is needed.
    -    o    Bottom of amine regenerator. Poor amine regeneration and high momentum of the vapours (or vapour — liquid) coming from the reboiler can impinge on the vessel wall and remove the protective iron sulphide layer.
    -    o    Amine contactor can suffer from corrosion problems in the bottom due to feed high momentum that impinges on the vessel wall.
    -    o    Any equipment made of carbon steel will suffer from cracking problems if it is not properly processed using the right chemistry, welded properly, checked for hardness and, if required, post weld heat treated.

Jun-2021
Andrew Layton, KBC, Andrew.Layton@kbc.global

Typically, materials selection in an amine unit is related to the H₂S loading designed for the amine units. Carbon steel is often adequate at modest H₂S loading with well controlled levels of contaminants. A change in corrosion rates can be triggered by several events:
- Increase in H₂S loading of the rich amine (also max loadings dependent on amine type)
- Increase in CO₂ loading such as if started co processing of bio feed on a hydrotreater
- Increase in circulation rates — corrosion erosion related to high contaminant concentrations and velocity
- O₂ increase leading to organic acids such as if water washing issues on FCC offgas systems upstream of the amine unit
- Too low a H₂S concentration in lean amine lines through over stripping in the amine regenerator. Very low H₂S loading removes the protective sulphide layer from the piping
- Increase in ammonia concentration in regenerator overheads such as through hydrotreating higher N2 feeds or deeper HDS / HDN levels of the hydrotreaters
- High levels of heat stable inorganic and organic salts formed via O₂ and often in gases from FCC or other cracking units
- Inorganic salts such as chlorides from exchanger leaks and fouling leading to under deposit pitting corrosion
- Change in amine type used

Jun-2021
Berthold Otzisk, Kurita Europe, berthold.otzisk@kurita-water.com

In amine plants, corrosion is a common problem when acid gases are removed. When corrosion occurs, it is highly localised — overall corrosion does not actually occur. The alkanolamines bind the acid gases in the absorber. Tertiary amines such as MDEA form much less corrosive amine salts compared to secondary amines or the even more corrosive primary amines.

If no corrosion has been noticed so far and now severe corrosion is observed, this can have different causes. In the first place, hydrogen sulphide (H₂S) and carbon dioxide (CO₂) can be the reason for increased corrosion.

There is usually an equilibrium between acid gases and the amine solution. If this equilibrium is shifted, the acid gases can be released again and attack the metal surfaces. Temperature increase or pressure reduction allow acid gases to escape from the solution, which can then lead to increased corrosion. The formation of a natural FeS protective layer is desired if the FeS scale is strong enough to form a protective layer. Fluid dynamics, temperature, pH, partial pressure of H₂S and CO₂, or the presence of surfactants or corrosion inhibitors can have a negative influence, which may increase corrosion. The strength of the protective FeS film is highest at pH 7-8. Above pH 8, it is more porous and less protective. Too much iron sulphide should be filtered out of the amine solution. If corrosion occurs in the overhead system of the regenerator, the use of neutral amine can be useful, as H₂S is bounded in the liquid phase and NH₃ is released. Heat stable salts can also initiate higher corrosion rates.

When dissociation of the salt is observed, a corrosion cell is formed with the metal. As a general rule, the concentration of heat stable amine salts should not exceed 10% of the total amine concentration. By adding NaOH or KOH, the concentration of heat stable salts can be kept stable. More salts will preferentially form with the strong base, NaOH, or KOH. Excessive injection of caustic should also be avoided.

Jun-2021
Chris Claesen, Nalco Water, Chris.Claesen@ecolab.com

Corrosion in amine units can be due to a variety of reasons. The most common ones are wrong operating conditions and amine contamination and degradation. First, you will have to do a root cause investigation looking at operating conditions, amine composition, and the location of the corrosion. An amine unit that is operated within design guidelines and with good amine quality will have very little corrosion issues even with carbon steel. Refiners can end up in a situation where the operating conditions or amine quality cannot be controlled within the recommended limits and in such a case corrosion inhibitors such as the Nalco Water Intercept programme can help control the corrosion in specific areas of the unit. In the long term it is best to make the necessary hardware modifications to bring the operating conditions and amine quality back within the recommended limits. Changes in crude slate and acid gas composition (more H₂S, NH₃ or HSAS precursors) can change the corrosion conditions in the amine unit and should trigger an amine unit MOC check.

Jun-2021