A promoter for selective H2S 
removal: part I

A new MDEA promoter achieves very low H2S lean loadings and the option for flexible design of acid gas enrichment units by varying absorber heights

Gerald Vorberg, Ralf Notz and Torsten Katz, BASF SE
Wieland Wache and Claus Schunk, Bayernoil Raffineriegesellschaft

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Article Summary

The selective removal of H2S has become an important topic over past decades. This is driven by several factors, one being the production of an H2S-enriched, and thus high-quality, Claus gas in MDEA-based acid gas enrichment (AGE) units.

Other fields where selective gas treatment would also be beneficial are natural gas and refinery applications. For sour gas fields, this application is becoming increasingly attractive due to limited sweet gas resources. For refineries, debottlenecking issues and an increased flexibility for processing different crudes are the most important drivers.

From an operational perspective, savings in energy and circulation rate, as well as a reduction in equipment sizing, are the obvious benefits of enhanced selective 
treatment. In addition, tight environmental regulations and sulphur specifications are attributed to this subject.

The principles for the selective removal of H2S with amine-based solvents follow three major routes:
• Hindered amines, controlling the selectivity primarily in the absorber
• Various design options and absorber internals, affecting the difference in CO2 and H2S mass transfer kinetics
• Promoted tertiary amines, focusing more on enhanced regeneration and thus leading to lower H2S loadings.

With respect to the final point, the advanced promoter system presented in this article can be a considerable leap forward for more flexible selective designs. Very low, achievable lean loadings are an option to adjust selectivity by varying the absorber height without losing control over a tight H2S specification with a sufficient safety margin.

This article gives an overview of the principles, while part II (see PTQ, Q2 2011) shows the ability of this promoter system to drop H2S lean loadings in a refinery amine system. 

Acid gas removal with amine-based solvents is a mature and widespread application in the oil and gas industry. Besides specific design variations, acid gas removal units (AGRU) always follow the principle of an absorber-regenerator configuration. First, acid gases are removed from the fluid stream in the absorber by the liquid solvent typically at 20–50°C and elevated pressures up to 80 bar, depending on the feed gas conditions. In a second step, the dissolved acid gases are desorbed in a regenerator at “inverse” conditions. Desorbed acid gases can be further processed in Claus sulphur recovery units (SRU), reinjected for enhanced oil recovery (EOR) or simply flared. When focusing on the two main acid gas components, CO2 and H2S, process designers differentiate between total acid gas removal and selective sulphur removal or simply selective removal. As the name implies, selective sulphur removal selectively removes H2S, while other acid gases, for instance CO2, are slipped into the treated gas.

Consequently, selective removal has a different focus compared with total acid gas removal processes, such as BASF’s aMDEA process, where simultaneous removal of H2S and CO2 is intended. This means that suitable solvents have different characteristics.

H2S selectivityDefinitions
In industry, various expressions for H2S selectivity are used to judge the selectivity of an absorption process with regard to H2S compared to CO2. In the following, the most important examples are given (cH2S and cCO2 stand for molar concentration in gas streams):

• H2S selectivity (rigorous definition)
H2S selectivity is calculated as: 

• CO2 co-absorption (or CO2 pick-up)
CO2 co-absorption in the absorber is specified as: 

CO2_co-absorption = 1- CCO2 treated gas
                                       CCO2 feed gas

•    CO2/H2S ratio comparison (often used for acid gas enrichment)
The decrease in CO2/H2S ratio indicates the efficiency of an acid gas enrichment unit: 

A proper comparison of these expressions for different solvents or applications must be evaluated with great care, since the absolute level of H2S in the treated gas is less considered. In other words, H2S selectivity is well defined, but not particularly suitable for judging H2S specifications in treated gas.
The following example, calculated according to the rigorous definition, might show the difference:

Feed gas:   H2S 1 v%     CO2 5 v%
Treated gas case 1:  CO2 1.5 v%  H2S 1 vppm → H2S selectivity = 1.428
Treated gas case 2:  CO2 1.5 v% H2S 50 vppm  → H2S selectivity = 1.421

Dependency on operating conditions
Selective treatment with amine-based solvents generally takes advantage of the rapid reaction of H2S compared to the kinetically hindered reaction of CO2; CO2 first has to react with water to form carbonic acid. In particular, tertiary amines are often used for selective applications, as they are unable to form carbamates, the only fast reaction involving CO2.
These are the reactions of tertiary amines in aqueous solutions:

Reaction of water and amine (fast)
R1R2R3N + H2O ⇔ R1R2R3NH+ + OH_
2 H2O ⇔ H3O+ + OH_

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