Mitigating corrosion in sweet gas units: a comparison between laboratory data and field survey

An extensive review of acid gas removal units covering 5 decades and more than 120 amine units showed that units treating sweet gases (i.e. with CO2 only) presented the worst risks of corrosion.

J Kittel, IFP Energies nouvelles
M Bonis, Total
G Perdu, Prosernat

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Article Summary

In some extreme cases, a quite uniform corrosion in an active mode was observed on stainless steel grades such as AISI 410 and 304L, despite apparently mild corrosive conditions. Strong scaling of the heat exchangers by corrosion products was also observed. A detailed analytical survey of those corrosive DEA units was then performed over more than two years. Immediately after fresh solvent swap, dissolved iron concentration increased until stabilisation at several hundreds of mg/L after a few months. Good correlation was found between dissolved iron, amine degradation, and the amount of scaling products that was recovered in the heat exchangers. Comparisons with similar units using activated MDEA revealed dissolved iron levels several orders of magnitude below those in DEA.

In order to understand more precisely the driving forces for steel corrosion and for the precipitation of corrosion products, a laboratory program was launched. Comparisons between different amines in rich and lean conditions were performed in autoclave. A spaecific protocol was developed which aimed at degrading the amine solutions and at providing dissolved iron before corrosion tests to image the degradation of industrial solvent in actual life of plant. The laboratory degraded DEA was successfully compared to an industrial DEA solution sampled in a gas sweetening unit experiencing corrosion problems. Active corrosion of carbon steel (CS), AISI 410 and even AISI 304L was reproduced in laboratory conditions with hot rich DEA and with industrial DEA solution as well. Industrial trends of strong precipitation of iron carbonate in the amine-amine exchangers could be explained. Iron solubility was found to depend on amine loading, with a lower solubility in rich conditions, thus a strong tendency to precipitate.

Based on a the same protocol to obtain degraded MDEA and energizedMDEA, the study further looked at the behaviour of those commonly used amines made of on the shelf and generic amine molecules.

The experience and know-how gathered from the feed-back, inspection and laboratory experiments is applied to understand the performance of existing units, for which carbon steel has been used extensively. When improvements are welcome, the key corrosion mitigating issues are exposed in term of appropriate amine selection for sweet or sour gases, flow velocities and procedures for solvent preservation. The article also discusses about material selection and replacement of carbon steel by appropriate corrosion resistant alloy (CRA) when needed and only on selected areas, as normal maintenance operations following periodic inspections. This considerably extends the service life, while also enabling operation above the initial specifications.

For newly built compact units, the design criteria focus on application of AISI 316L, now preferred instead of lower grades like 304L or AISI 410, to areas potentially prone to corrosion. With appropriate use of CRAs, acid gas loadings of 0.85 or even higher can be considered in design, without velocity limitations on the rich amine lines or stringent material selection. Furthermore, the amine units based on the AdvamineTM technologies remain fully versatile and flexible to encompass the widest range of amines, including MDEA and energizedMDEA.

Corrosion likelihood in amine units
Corrosion in amine units represents one of the main operational problems. A recent survey by Tems and Al-Zahrani on the evaluation of cost of corrosion in gas sweetening plants concluded that 25 % of the maintenance budget was committed to corrosion control1. In such complex units, numerous pieces of equipment are exposed to equally numerous types of corrosion, including both weight loss corrosion and cracking modes. As far as weight loss corrosion is concerned we can adopt the classification proposed by Nielsen2, who identifies:
• wet acid gas corrosion,
• amine solution corrosion.

Wet acid gas corrosion may be encountered in all parts of the unit in contact with an aqueous phase with a high concentration of dissolved acid gases CO2, H2S, as well as HCN for refinery units. This type of corrosion is found primarily in zones where the gaseous phases have high concentrations of acid gases and where water may condense, mainly at the bottom of the absorber and at the top of the regenerator.

For gas containing mostly CO2, parts of the installation made from carbon steel may suffer fast wet CO2 corrosion, up to several mm/year. In the presence of H2S, this uniform corrosion is generally lowered by the formation of a protective iron sulphide layer. A minimum H2S/CO2 ratio of 1/20 is often considered as sufficient to avoid risks of CO2 corrosion3,4.

The second type of corrosive media found in acid gas removal units is the amine solution itself. Generally, amines are not intrinsically corrosive, since they associate both high pH and low conductivity. They may nevertheless become corrosive when they absorb CO2 or H2S or when exposed to degradation. Furthermore, since the treatment units operate in semi-closed circuit, the solvent itself now circulates in closed loop equipped with water wash sections that limit the solvent losses to the minimum. The solvent may then become polluted with possibly corrosive degradation products.

No consensus has yet been reached concerning the mechanisms of corrosion by amine solutions. The models proposed vary depending on the type of amine (in particular, primary, secondary and tertiary), the H2S/CO2 ratio in the gas to be treated, the possible presence of oxygen either as contaminant in the circuit or as component of the input gas (e.g. CO2 capture in fumes). For more information on specific corrosion models, the reader may refer to the relatively extensive bibliography on this subject2,5-8.

We may nevertheless identify some systematic trends governing the corrosiveness of acid gas chemical solvents. Acid gas loading and temperature are usually considered as the most important factors. The acid gas loading (α) is defined as the quantity of acid gas absorbed by a defined quantity of solvent and is often expressed in moles of acid gas per mole of amine. Increasing the acid gas loading increases the corrosiveness of amine solutions7-10. Temperature generally has an extremely important effect on corrosion phenomena since most electrochemical reactions involved are thermally activated. It is common practice in industry to consider that the corrosion rate is doubled when the operating temperature increases by 10°C to 20°C. For gas treatment units, the effect of temperature is relatively difficult to assess on an individual basis. Temperatures vary widely in the installation, with extreme values ranging from 40°C in the absorber up to 130°C in the regenerator bottom section and in the reboiler. However, these temperature variations have a significant effect on the chemistry of the solution, in particular the acid gas loading. Taking into account both the loading and the temperature, we may consider that the main corrosion risks are encountered in areas with high loading and high temperatures8,11. These conditions are generally found in the rich amine line from absorber bottom to the regenerator through the rich amine/lean amine inter-heat exchanger.

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