Material Selection for Amine Service

Introduction:

Amine are compounds formed by replacing hydrogen atoms of ammonia (NH₃), an organic radical. The complex chemical composition of the acid gas removed by amine solutions is simplified in the following two conditions.

H₂S + R₂NH ↔ R₂NH₂⁺ + HS^–

The refineries and gas plants are also affected by the presence of CO₂ as the hydrate formation is affected by the presence of CO2 affecting the product quality such as ethylene.

CO₂ + R₂NH ↔ R2NH₂⁺ + R₂NCOO^–

As stated above different types of amine have different reactions, the primary amines NH₂R that include Methanolamine – often referred as (MEA), diglycolamine known as DGA.

The methanol molecules in MEA loses an H bond and attaches to the amine molecule (CH₂OHNH₂), which also has an H bond.

In the secondary amines NHR₂ like diethanolamine (DEA), and disopropanolamine (DIPA) which are similar except that there are two alcohol molecule for one molecule of amine. This gives the formula NHR₂, where R is the alcohol radical.

In the tertiary amines NR₃ like diethanolamine (DEA), disopropanolamine (DIPA) and methyldiethanolamine (MEDEA) there are three alcohol molecules for one atom of nitrogen (N).

All these different amines have different reactions and their reactions and corrosion modes can vary significantly.

Corrosion challenges faced by amine units:

As is known that the amine by itself is not the agent of corrosion, pure amines are highly alkaline and not generally corrosive, but the presence of acid gases like H₂S and CO₂ which is stripped out of feed gas, off-gas and olefinic and saturated liquefied petroleum gas (LPG) and the presence of amine. These later environments caused during Catalytic Cracking process1. The SRUs in refineries also use amines. The amine degradation products also contribute to corrosion problems. These corrosion and cracks and failures may manifest in one or a combination of following types of modes.

• Sulfide Stress Corrosion (SSC)⁴

Atomic hydrogen diffusion in carbon steel, increases the hardness of steel and embrittels it. The cracks are transgranular in low strength steels and are mixed mode or intergranular in higher strength steels. Localized had spots are also manifest in steel. The weld and HAZ are more susceptible to SSC, this emphasizes the importance of right WPS developments and inspection methods.

• Hydrogen Induced Cracking (HIC), Hydrogen blistering⁴

Hydrogen blistering is one of the forms that is covered under Hydrogen Induced Cracking (HIC) mode of corrosion and failure.  In this process hydrogen atoms enter the steel and accumulate at the voids within the steel. Successive blisters join by internal cracking and ultimately leads to material failure. Cleanliness of steel production methods where in the inclusion type and size is strictly controlled is the primary way to reduce possibility of HIC.

• Stress Oriented Hydrogen Induced Cracking (SOHIC)⁴

Stress Oriented Hydrogen Induced Cracking, as the name suggests is another form of HIC. It usually occurs in the parent metals opposed to weld metal or HAZ. However it can occur anywhere adjacent to HAZ or any location in the metal where stresses are concentrated.

• Alkaline stress corrosion cracking (ASCC)

As the name suggests this is a corrosion mode in an alkaline environment, in the presence of H₂S and CO_2. Higher tensile stress in the material contributes to manifest the failure through cracking. The cracks are branched and intergranular.

The crack occurrence is sensitive to temperature, often associated with higher temperature ranges. Corrosion occurs in lean amine treating solutions that have H₂S and CO₂ and the pH of the solution is between 8 and 11⁸. The corrosion occurs when the protective film ruptures due to stress and iron is dissolved from local anodic points.

For stainless steel lower grades of steels are more susceptible to caustic SCC, in highly caustic environment at temperatures above 120^oC. In more demanding environments and in industries like paper and pulp use of duplex steel is more economical solution.

Welds in non-stabilized stainless steels like Type 304 and 316 are more susceptible to intergranular corrosion (IGC), due to sensitization during welding.

Once again a well thought-out development of welding procedure coupled with proper selection of steel type and grade is the solution.

As is evident, general corrosion for this discussion only this term also includes pitting (which is part of another generic term called localized corrosion) and cracking are the two distinctive modes of damages that an amine unit may face. We will briefly discuss these in the light of an amine unit.

• Corrosion in amine units

We know that corrosion is caused by the dissolved acid gases and not by amine itself. The salts that are stable in heat a byproduct of amine degradation can also cause significant corrosion.

In a low process system amine units used to remove CO₂ are more severe than the units that are used to remove H₂S, or H₂S and CO₂ combined.^{1, 5}

In a high pressure system that has higher pH₂S the carbon steel corrosion is significant. Studies¹ have indicated and support the fact that corrosion rates are lower at higher concentration rate, this can be attributed to lower circulation rate at higher concentration, and lower circulation can be linked to less propensity for erosion. For carbon steel the maximum limit on the velocity that would case erosion is 1.5m/s. For stainless steels a maximum and minimum velocity limit is set for different grades.

Issues that are related to amine processes.

As we have seen there are various application related to amine systems, these systems use different processes as suitable to the plant. They create different environment for corrosion and or cracking. There are basically four distinct processes in amine system that is identified and can be discussed.

• Acid gas removal process

The system involves where in the Gas is fed in to the absorber below bottom tray. The gas rises against a lean solvent i.e. amine, with treated gas exiting the top of the absorber column. The gas may go through a knock out drum that disengages the residual solvent. This operation is generally at low temperature as low as 16^oC but the pressure is often high. The exit temperature of the gas at the absorber is about 40^oC.

The CO² gas forms carbonic acid which is particularly aggressive to steel. In normal circumstances the shell would protect itself by stable iron oxide-carbonate layer. If however any turbulence is caused or inhibitor treatment is implemented the layer protecting the shell could be destabilized.

• Amine regeneration

In this process the rich amine liquid from exchanger enters the regeneration column and moves downwards from the top of the column at this point the temperature is about 80^oC, as the solvent flows down the column the acid gases are stripped off by rising steam. The lean solvent now exit through the bottom of the regeneration column at about 110^oC temperature.

During this process feed fluid does flash, this can lead to some failure of Splash plate by erosion, if the plate fails the erosion can continue on the column wall opposite the inlet, the other impact of this failure can be seen in presence of higher moisture in the stream that comes out of the column.

Higher corrosion can be seen at the points where the flash of acid gases occurs. Points to monitor would be the regenerator reboiler and lower portions of the Regenerator column.

If the system contains CO₂ then the overhead will be affected. This is due to the higher alkalinity of the injected amine.

Chloride stress corrosion cracking is possible if chloride level exceeds 1000ppm. The reboiler in the system is generally not affected by amine stress corrosion unless the material is in high residual stress condition an indication of or as a result of poor PWHT or bad weld fit-ups, and threaded connections.

• Amine circulation

In the absorber column the entry temperature of lean solvent is 40^oC and its exit temperature is over 50^oC, now the amine is rich amine.

In a typical amine sweetening plant the rich amine is flashed off before its entry in to a series of heat exchangers to be heated to above 90^oC temperature. The lean solvent exits through the bottom of the column called either a stripper of Regenerating column at this exit the temperature is above 100^oC. The exiting solvent is cooled to about 50^oC temperature before its entry into an Absorber through the top tray.

As the rich amine leaves through the bottom of the column, some vortex breaker designs create enough pressure drop to develop bubbles in the fluid, the collapse of these bubbles on the metal surface especially on the exit nozzle pipe wall to cause cavitation damages.

As is evident that in this process there is significant process variations by way of dropping and raising of temperature and pressures. This requires various components like control and isolation valves. Design and sizing of these components and their locations is important a careful design analysis must be conducted to minimize corrosion related damages. In correct sizing can lead to higher flow velocities that may lead to damages to reducers and other fittings in the system. A metallurgical solution is possible by upgrading the materials of the components but that requires proper study of all fittings in the system.

It is known fact that the bypass lines around the valves have greater propensity to corrosion, this is because the bypass isolation valve remains closed most of the times resulting in a dead-leg. On the hand the bypass line above the control valve may be subject to gases that can stop wetting the surface by amine. An action that puts the material exposed to subsequent condensation developing carbonic acid solution leading to sever corrosion.

The bypass lines below the control valve may be affected by sedimentation and under deposit corrosion phenomenon.

The amine circulation circuits have a flash tank, the inlet nozzles are prone to erosion and the tank itself is prone to under deposit corrosion if not properly sized and designed. Under deposit corrosion is possible in these tanks because the flow velocity is very low in the vessel causing sedimentation.

Other design considerations may include entry point of rich solvent in the heat exchangers, the entry in the tube side is often practiced for the rich solution basically because the rich solution is more fouling. It is good practice to keep the inlet of the rich amine at a lower level than the outlet.

• Heat stable amine salts (HSAS)

This one of the common challenges faced by amine units. The units are contaminated by the incursion of acid or inorganic salts. This results in degradation of solvents. In primary amine (MEA) plants this is resolved by “reclaimers” however this is not feasible in secondary (DEA) and tertiary amines like MDEA solvent units.

The challenge manifest itself in the form of entry of oxygen that can form carboxylic acids or H₂S that can react with the salts to form strong acid anions such as sulphate and thiosulphates. In the absorber column the process starts with the acid gases being absorbed which is and exothermic reaction. The rich liquid is heated in the regenerating column which reverses the reaction. If the absorbed acid is strong where the acid dissociation constant (pKa) is lower than the amine, the amine is deactivated in terms of gas treating. The buildup of HSAS is a result of formate incursion. These acids are not thermally re generated, but they can include acetate, oxalates, gycolate, chloride, sulphate, thiosulphate, thiocynate and propionate. There is a study by Burns et al ⁶ that indicates that the well treatment fluids like acetic acid and hydrochloric acid also result in HSAS. The presence of chlorides and sulphates information waters also contribute to HSAS formation.

Other impact of salt corrosion is manifest in scaling, they affect heat transfer, under deposit corrosion, foaming due to suspended solids.

HSAS is a severe problem if not treated, it can cause significant loss of metal in reboiler in very short time. The issue of HSAS can be addressed in several ways including the following.

1. Electrolysis
2. Ion exchange
3. Use of neutralizers to raise the pH of the solution that would convert the amine salts to inorganic salts. It is to be noted that the inorganic salts can increasing fouling and lead to crevice corrosion.
4. Vacuum distillation, this process has limited application as it generates waste. As we have noted from above discursions the corrosion mode for each application is not same and conditions are significantly different. This variation leads to the specific consideration of material that would be suitable for specific application. The selection of material for above discussed application is not singular.
5. Carbon steel and different grades of stainless steel are often used in most applications. The basis of selection of course depends on the susceptibility of damage and risk of failure. The later part -the risk- also includes the ability to stage a successful repair and accessibility to components. In this respect the design of components carry significant influence. This apart from the development of a good welding procedure the design allows or restricts the accessibility and handling of welding related activities.
6. Material Selection⁴

1. For Acid gas Removal unit, the shell of the vessel is usually of carbon steel that is lined often metallurgical bond clad stainless steel of type 304 or type 316. The internals of the vessels and nozzles are similarly either clad of made of specified stainless steel. The use of type 316 is more preferred over type 304 as the pREN of type 316 steel is about 22.5 and it can withstand chlorides below 1000 ppm and Naphthenic acid attack the attacks.

The presence of chlorides to 1000 ppm and greater however will require that materials like alloy 825 or UNS S 31254 (254SMO) is considered.

If it can be assed that scaling level and its stability can be established then it is possible to use carbon steel. However system upsets and changes in flow etc., can cause significant damage and quick failure of vessel and components.

The design of system should follow principles of good flow by removing or at least reducing turbulence causing elements from the system.

1. The rich amine liquid enters the Amine regeneration unit, the corrosion mode is different in Re-gen columns, flashing of the feed and temperature are part of the system. The demands of material selection are different.

Vessels, columns, valves and piping:

The re-Gen columns are constructed out of clad carbon steel. The cladding is done with ferritic stainless steel of Type 405 (UNS S 40500) steel. Use of other ferritic stainless steels like 410, is also used however in hot rich environment type 410 steel have shown excessive corrosion. Other grades of ferritic steels like 410, 420, or martensitic steel grade 440 exhibit higher yield and corresponding hardness that goes contrary to the design philosophy. The advantages of using type 405 is its lower yield strength and the ease of welding without post weld heat treatment.

Use of austenitic steel grades like type 304 is to the internals of the columns and valves down stream of control valves, limit the damages caused by high rate of corrosion, primarily due to higher flow rate and resulting turbulence.

Tubes:

Pitting of the tube is the most common corrosion issue identified in the reboiler. Vapor blanketing causes groves on the reboiler tubes resulting in reduction in wall thickness and overheating of tube bundle. This also increases the possibilities of velocity influenced corrosion. The blanketing effect reduces the overall surface area of tube for heat transfer, which in turn increases the heat flux through the remaining tubes of the bundle.

Monel metal tubes (UNS N04400) are often best in environment that has CO₂, Monel is a Copper -nickel solid solution alloy.

However if CO₂ is not present in the system then use of austenitic steel type 304 or 316 is most suited for situation where vapor blanketing persists. If all these issues are resolved in the process then and only then it is vise to use carbon steel tubes.

Pump and impellers:

The pump impellers of high silicon cast iron is successfully used in a low pressure amine service. Normal cast iron is also used however their performance is not as impressive and cost effective as that of high silicon cast iron impellers.

For services where high pressure amine is used the material to be considered is austenitic steel type 316 or its cast version grade CF8M.

1. The selection of suitable material for use in amine circulation plant is based on several factors of the plant environment. The decision should be based on consideration of possible turbulence areas, temperature and the lean or rich solvents in specific flow. The lean solvent is hottest as it leaves the regeneration column.

The heat exchanger tube and shell material selection is also based on if the solvent would flow through the shell side or tube side, this is the factor related to the temperature identified above. Since the hottest is the lean solvent as it leaves the Regeneration column this would flow through the tube side of the exchanger. The release of gases would start at about 85^oC. When such is the process design condition it is good to have exchanger tubes out of stainless steel. The shell side would be relatively less susceptible to corrosion it can be designed out of carbon steel with suitable corrosion allowance.

If however the solvent is rich and viscous the temperature would be cooler, it will flow through the shell area this will reduce the required heat transfer area, and also the size of the heat exchanger.

Cladding in some conditions is an option both due to the erosion possible due to flow related turbulence, especially those of nozzles. Similar conditions may sometime also prompt a decision to clad the shell internal surface.

Designing for repair and maintenance    

The amine plant in general should be designed with the idea that in the course of its service repair and maintenance will be required. Absorbers and other equipment will require maintenance for safe operation of the plant. As best as possible full access to the equipment and piping should be provided.  The activity of repair and maintenance includes removal, replacement, modifications and welding and joining activities.

Of all repair and maintenance activities welding is most critical. A suitable welding procedure specification should be developed and qualified to meet design specification often ASME Section VIII which leads to ASME section IX, and requirements of NACE RP 0472 for control of cracking in carbon steel weldments. This NACE recommended practice addresses some of the issues like SCC and ASCC as discussed above, and related to welding controls and additional steps that should be taken to prevent failures of weld and weldments.

The NACE recommended practice recommends control of steel’s chemistry, hardness of weld and post weld heat treatment of carbon steel.

API also has a recommended practice (RP 582) which is also a very useful tool relating to welding. It provides information similar to that is contained in several of ASME sections, for example; welding consumable like welding wires, electrodes and gases are contained in ASME Section II part C, and PWHT requirements may be found in ASME Section VIII, Sections III (nuclear), Sections I and IV (for boilers) or ASME B 31.3 for piping etc.

References:

1. API     RP 945 Avoiding Environmental Cracking in Amine Units.
2. API  RP 582   Welding Guidelines for the Chemical, Oil, and Gas Industries.
3. NACE             RP 0472 Methods and Controls to Prevent In-Service Environment Cracking of carbon steel Weldments in Corrosive Petroleum Refining Environments.
4. Ramesh Singh, Material Selection for Sour Service Environment, Pipeline and Gas Journal February 2010, pp 50-51 & 69 -70.
5. Shmeal  W.r. Macnab A.J. and Rodes P.R, Corrsoion in Amine/Sour Gas Treating Contactors, Chemical Engineering Progress, Vol.74, No. 3.(1978)
6. Burns D., Gregory R.A., The UCARSEP process for on-line Removal of non-Regenerable Salts from amine Units, Laurence Reid Gas Conditioning Conference 1995.
7. API     RP 945, Avoiding Environmental Cracking in Amine Units.
8. Safruddin, Sutopo and Rahmat, Twenty Years’ Experience in Controlling Corrosion in Amine Unit, Badak LNG Plant Corrosion 2000.