Removing H2S from gas streams

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Removing H2S from gas streams

Nagl, G.J.

When selecting an H2S-removal technology, one must consider the operating pressure of the system, the concentration of H2S in the inlet stream, the presence of other contaminations, local regulations, and economics. This article compares the four dominant approaches - the use of liquid or solid H2S scavengers, liquid redox processes, and a Claus system with a tailgas-treatment unit - from both a technical and an economic standpoint. Each can remove and recover 99.9+% of H2S from natural gas streams. With the exception of the Claus approach, each may also be used to remove H2S from other industrial gas and fluegas streams. Although H2S is rather insoluble in water, the dilute solution that does form is acidic, and can be very corrosive to pipelines and equipment. However, it is its extreme toxicity - H2S is more lethal than hydrogen cyanide - that is often the driving force for removing H2S from natural gas. A table schedules selection guides to H2S removal for all four approaches. If turndown is a major concern, solid scavengers and liquid-redox systems should be considered. If waste-product disposal is a concern, solid scavengers should be ruled out. From an economic perspective, systems handling less than 200 kg/day of H2S should use scavengers, while those with greater than 20 tons/d of H2S should use a Claus-tailgas system. Anything in between should consider a liquid-redox system.